In-situ kerogen conversion and recovery

ABSTRACT

Disclosed herein are methods for extracting a kerogen-based product from subsurface (oil) shale formations. These methods rely on chemically modifying the shale-bound kerogen using a chemical oxidant so as to render it mobile. The oxidant is provided to a formation fluid in contact with the kerogen in the subsurface shale. An alkaline material is also provided to the formation fluid to mobilize organic acids which are produced during oxidation of the kerogen. A mobile kerogen-based product which includes the organic acids is withdrawn from the subsurface shale formation and further processed to isolate the organic acids contained therein.

RELATED APPLICATIONS

The subject application claims priority to U.S. Provisional Application Ser. No. 61/426,340, filed Dec. 22, 2010, the contents of which are incorporated herein by reference in their entirety. This application is also related to U.S. application Ser. No. ______ (attorney docket number 70205.0216USU2), entitled “In-Situ Kerogen Conversion and Product Isolation” filed Dec. 22, 2011; U.S. application Ser. No. ______ (attorney docket number 70205.0216USU3), entitled “In-Situ Kerogen Conversion and Upgrading” filed Dec. 22, 2011; U.S. application Ser. No. ______ (attorney docket number 70205.0216USU4), entitled “In-Situ Kerogen Conversion and Recycling” filed Dec. 22, 2011, and U.S. application Ser. No. ______ (attorney docket number 70205.0232US01), entitled “Preconditioning a Subsurface Shale Formation by Removing Extractible Organics” filed Dec. 22, 2011. The contents of these four related applications are incorporated herein by reference in their entirety.

BACKGROUND

If proponents of Hubbert peak theory are correct, world oil production will soon peak, if it has not done so already. Regardless, world energy consumption continues to rise at a rate that outpaces new oil discoveries. As a result, alternative sources of energy must be developed, as well as new technologies for maximizing the production and efficient consumption of oil. See T. Mast, Over a Barrel: A Simple Guide to the Oil Shortage, Greenleaf Book Group, Austin, Tex., 2005.

A particularly attractive alternative source of energy is oil shale, the attractiveness stemming primarily from the fact that oil can be “extracted” from the shale and subsequently refined in a manner much like that of crude oil. Technologies involving the extraction, however, must be further developed before oil shale becomes a commercially-viable source of energy. See J. T. Bartis et al, Oil Shale Development in the United States: Prospects and Policy Issues, RAND Corporation, Arlington, Va., 2005.

The largest known deposits of oil shale are found in the Green River Formation, which covers portions of Colorado, Utah, and Wyoming. Estimates on the amount of recoverable oil from the Green River Formation deposits are as high as 1.1 trillion barrels of oil—almost four times the proven oil reserves of Saudi Arabia. At current U.S. consumption levels (approximately 20 million barrels per day), these shale deposits could sustain the U.S. for another 140 years (Bartis et al.) At the very least, such shale resources could moderate the price of oil and reduce U.S. dependence on foreign oil.

Oil shale typically consists of an inorganic component (primarily carbonaceous material, i.e., a carbonate), an organic component (kerogen) that can only be mobilized by breaking the chemical bonds in the kerogen, and frequently a second organic component (bitumen). Thermal treatment can be employed to break (i.e., “crack”) the kerogen into hydrocarbon chains or fragments, which are gas or liquids under retort conditions, and facilitate separation from the inorganic material. This thermal treatment of the kerogen is also known as “thermal upgrading” or “retorting,” and can be done at either the surface or in situ, where in the latter case, the fluids so formed are subsequently transported to the surface.

In some applications of surface retorting, the oil shale is first mined or excavated, and once at the surface, the oil shale is crushed and then heated (retorted) to complete the process of transforming the oil shale to a crude oil—sometimes referred to as “shale oil.” See, e.g., Shuman et al., U.S. Pat. No. 3,489,672. The crude oil is then shipped off to a refinery where it typically requires additional processing steps (beyond that of traditional crude oil) prior to making finished products such as gasoline, lubricant, etc. Note that various chemical upgrading treatments can also be performed on the shale prior to the retorting, See, e.g., So et al., U.S. Pat. No. 5,091,076.

A method for in situ retorting of carbonaceous deposits such as oil shale has been described in Kvapil et al., U.S. Pat. No. 4,162,808. In this method, shale is retorted in a series of rubblized in situ retorts using combustion (in air) of carbonaceous material as a source of heat.

The Shell Oil Company has been developing new methods that use electrical heating for the in situ upgrading of subsurface hydrocarbons, primarily in subsurface formations located approximately 200 miles (320 km) west of Denver, Colo. See, e.g., Vinegar et al., U.S. Pat. No. 7,121,342; and Berchenko et al., U.S. Pat. No. 6,991,032. In such methods, a heating element is lowered into a well and allowed to heat the kerogen over a period of approximately four years, slowly converting (upgrading) it into oils and gases, which are then pumped to the surface. To obtain even heating, 15 to 25 heating holes could be drilled per acre. Additionally, a ground-freezing technology to establish an underground barrier around the perimeter of the extraction zone is also envisioned to prevent groundwater from entering and the retorting products from leaving. While the establishment of “freeze walls” is an accepted practice in civil engineering, its application to oil shale recovery still has unknown environmental impacts. Additionally, the Shell approach is recognized as an energy intensive process and requires a long timeframe to establish production from the oil shale.

In view of the aforementioned limitations of the above methods, simpler and more cost-effective methods of extracting the kerogen from the shale would be extremely useful.

SUMMARY OF THE INVENTION

The present invention is directed to a process for producing mobile products from the organic matter that occurs in subsurface oil shale. Among other factors, the process is based on the discovery that kerogen in oil shale can be made to react at temperatures below pyrolysis temperatures to produce mobile reaction products that can be removed from the subsurface shale formation, isolated in surface facilities and upgraded to produce useful products, refinery feedstocks, fuel and lubricant blendstocks, reaction intermediates and the like. The process for extracting a kerogen-based product from a subsurface shale formation comprises the following steps: providing an oxidant to kerogen in subsurface shale; contacting the kerogen in the subsurface shale with the oxidant at a temperature in the range from 0° C. and 200° C. to form organic acids; and mobilizing at least a portion of the organic acids from the subsurface shale to produce a mobile kerogen-based product.

Further to the invention is a process for extracting a kerogen-based product from a subsurface shale formation comprising subsurface shale, the process comprising the steps of: providing an oxidant to a fluid in a subsurface shale formation that contains kerogen, to produce a formation fluid; contacting the kerogen in the subsurface shale with the formation fluid at a temperature in the range of between 0° C. and 200° C. to form organic acids; providing an alkaline material to the formation fluid to form a mobile kerogen-based product that contains organic acids; recovering at least a portion of the mobile kerogen-based product from the subsurface shale formation; and isolating at least a portion of the organic acids from the mobile kerogen-based product.

The composition of the formation fluid is tailored by providing an oxidant to the fluid. In one embodiment, the process comprises providing a reactive fluid containing the oxidant to the formation. In one embodiment, the formation fluid contains in the range from 0.1 wt. % to 40 wt. % of the oxidant.

In one embodiment, the formation fluid is further tailored for mobilizing at least a portion of the organic acid reaction products from the kerogen conversion reactions. In one embodiment, the formation fluid which is tailored for mobilizing the products has a pH of at least 7. In one embodiment, the high pH formation fluid comprises an alkaline material selected from the group consisting of a carbonate, a bicarbonate, an oxide and a hydroxide. In one embodiment, the alkaline material is supplied to the formation fluid by a reactive fluid

One or more oxidants are provided to the formation fluid for converting the kerogen. In general, the oxidant is selected for its reactivity for conversion of organic materials in the shale at low temperatures. In general, reaction temperature is in the range from 0° C. to 200° C.

At least a portion of the organic acids that are produced are in the C₃₅+ range. In one embodiment, at least 50 wt. % of the organic acids in the mobile kerogen-based product is in the C₃₅+ range. Furthermore, at least 20 wt. % of the C₃₅− organic acids in the mobile kerogen-based product is in the C₈ to C₁₂ range.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a block diagram illustrating an exemplary sequence of steps involving the provision of a reactive fluid to a subsurface shale formation that contains kerogen, the recovery of a mobile kerogen-based product from the formation and the isolation of organic acid products from the mobile kerogen-based product.

FIG. 2 is a block diagram illustrating the added step of passing an organic extraction fluid to the mobile kerogen-based product for extracting at least a portion of the organic acids contained in the mobile kerogen-based product.

FIG. 3 is a block diagram illustrating an exemplary sequence of steps involving the provision of a reactive fluid to a subsurface shale formation that contains kerogen, the further provision of an extractive fluid for mobilizing organic acids that are generated from kerogen reactions, the recovery of a mobile kerogen-based product from the formation and the isolation of organic acid products from the mobile kerogen-based product.

FIG. 4 illustrates carbon chain-size distribution of low molecular weight acids in kerogen permanganate oxidation products determined by gas chromatography/mass spectrometry.

FIG. 5 illustrates carbon chain-size distribution of hydrocarbon products formed by pyrolysis of high molecular weight organic acids in kerogen permanganate oxidation products determined by pyrolysis gas chromatography/mass spectrometry.

DETAILED DESCRIPTION OF THE INVENTION Introduction

The present invention is directed to methods of extracting a kerogen-based product from subsurface shale formation comprising kerogen in an inorganic matrix. The methods rely on chemically modifying the shale-bound kerogen to render it mobile using an oxidant that is provided to the kerogen in the subsurface shale in a liquid medium. The oxidant converts the kerogen to a mobile kerogen-based product at temperatures below that at which the kerogen thermally decomposes by pyrolysis or thermal cracking. The oxidant is maintained in the subsurface shale formation for sufficient time to significantly reduce the oxidation activity of the oxidant. The present invention is also directed to systems for implementing such methods.

The process is for the conversion of carbonaceous deposits into mobile products, which may be recovered for use in the generation of energy and/or in the production of fuels, lubricants, solvents and/or petrochemicals that are generally formed during petroleum processing and refining. Any carbonaceous deposit may be beneficially treated by the process. Exemplary deposits include oil shale, coal, tar sands, heavy oil and the like. In the following description of the process, specific attention is paid to converting the hydrocarbonaceous material that occurs in what is commonly termed “oil shale”, with the understanding that application of the process in its general form is not so limited.

DEFINITIONS

In accordance with this detailed description, the following abbreviations and definitions apply. It must be noted that as used herein, the singular forms “a”, “an”, and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to an “oxidant” includes a plurality of such.

As used herein, a range encompasses all values within the limits of the stated range, including the end members of the range. In an illustrative example, “having a pH in a range from 8 to 12” includes all integer and fractional values from 8 and 12, including a pH of 8 or a pH of 12.

As used herein, the terms “hydrocarbon” or “hydrocarbonaceous” or “petroleum” are used interchangeably to refer to material originating from oil shale, coal, tar sands, crude oil, natural gas or biological processes. Carbon and hydrogen are major components of hydrocarbons; minor components, such as oxygen, sulfur and nitrogen may also occur in some hydrocarbons. The hydrocarbon fraction includes both aliphatic and aromatic components. The aliphatic component can further be divided into acyclic alkanes, referred to as paraffins, and cycloalkanes, referred to as naphthenes. A paraffin refers to a non-cyclic, linear (normal paraffin) or branched (isoparaffin) saturated hydrocarbon. For example, a C₈ paraffin is a non-cyclic, linear or branched hydrocarbon having 8 carbon atoms per molecule. Normal octane, methylheptane, dimethylhexane, and trimethylpentane are examples of C₈ paraffins. A paraffin-rich feed comprises at least 10 wt %, at least 20 wt % or even at least 30 wt % paraffins. For example, a C₈ rich paraffinic feedstock contains at least 10 wt. % C₈ hydrocarbons.

As disclosed herein, boiling point temperatures are based on the ASTM D-2887 standard test method for boiling range distribution of petroleum fractions by gas chromatography, unless otherwise indicated. The mid-boiling point is defined as the 50% by volume boiling temperature, based on an ASTM D-2887 simulated distillation.

As disclosed herein, carbon number values (i.e., C₅, C₆, C₈, C₉ and the like) generally refers to a number of carbon atoms within a molecule. Carbon number ranges as disclosed herein (e.g., C₈ to C₁₂) refer to molecules having a carbon number within the indicated range (e.g., between 8 carbon and 12 carbon atoms), including the end members of the range. Likewise, an open ended carbon number range (e.g., C₃₅+) refers to molecules having a carbon number within the indicated range (e.g., 35 or more carbon atoms), including the end member of the range. As described herein, carbon number distributions are determined by true boiling point distribution and gas liquid chromatography.

Unless otherwise specified, feed rate to a catalytic reaction zone is reported as the volume of feed per volume of catalyst per hour. In effect, the feed rate as disclosed herein, referred to as liquid hourly space velocity (LHSV), is reported in reciprocal hours (i.e., hr⁻¹).

As used herein, the value for octane refers to the research octane number (RON), as determined by ASTM D2699.

The term “surface facility” as used herein is any structure, device, means, service, resource or feature that occurs, exists, takes place or is supported on the surface of the earth. The kerogen products that are generated in the process disclosed herein are recovered in surface facilities and upgraded or transported for upgrading.

“Shale,” as defined herein, generally refers to “oil shale” and is a general term applied to a group of rocks rich enough in organic material (called kerogen) to yield petroleum upon pyrolysis and distillation. Such shale is generally subsurface and comprises an inorganic (usually carbonate) component or matrix in addition to the kerogen component.

A “subsurface shale formation,” as defined herein, is an underground geological formation comprising (oil) shale. The subsurface shale formation comprises kerogen in an inorganic matrix.

A “low-permeability hydrocarbon-bearing formation,” as defined herein, refers to formations having a permeability of less than about 10 millidarcies, wherein the formations comprise hydrocarbonaceous material. Examples of such formations include, but are not limited to, diatomite, coal, tight shales, tight sandstones, tight carbonates, and the like.

“Kerogen,” as defined herein and as mentioned above, is an organic component of shale. On a molecular level, kerogen comprises very high molecular weight molecules that are generally insoluble by virtue of their high molecular weight and likely bonding to the inorganic component or matrix of the shale. In a geologic sense, kerogen is a precursor to crude oil. Kerogen is typically identified as being one of five types: Type I, Type II, Type II-sulfur, Type III, or Type IV, based on its C:H:O ratio and sulfur content, the various types generally being derived from different sources of ancient biological matter.

“Kerogen-based,” and “kerogen-derived are terms used herein to denote a molecular product or intermediate derived from kerogen, such derivation requiring a chemical modification of the kerogen, and the term being exclusive of derivations carried out over geologic timescales.

“Extractible organics” are organic components of the subsurface shale formation that are at least partially soluble in an organic solvent. In contrast, the kerogen is not soluble in organic solvent. This organic component that is at least partially soluble is referred to herein as “extractible organics”. This extractible organic component includes what is commonly referred to as “bitumen”. The extractable organic component is a solid or semi-solid material that is soluble or at least partially soluble in an organic solvent. As such, the extractable organic component can be removed by extraction using an organic solvent. Extraction of the extractable organic component makes the kerogen more accessible. In the present methods, extraction of the extractable organic component makes the kerogen more accessible to oxidants for reaction to create mobile kerogen-based product. Extraction of the extractable organic component is disclosed in U.S. application Ser. No. ______ (Docket No. 70205.0232US01), “Preconditioning a Subsurface Shale Formation by Removing Extractable Organics”, filed Dec. 22, 2011, the contents of which are incorporated herein by reference in their entirety.

“Organic acid” is a term used herein to denote a molecular entity containing at least one carboxylic acid functional group, either in the non-ionized form (e.g., —COOH), in the ionized form (e.g., —COO—), or salts thereof. The term “organic acid” is meant to encompass a high molecular weight kerogen fragment (e.g., a molecular mass of up to 12,000 to 15,000 daltons and higher) comprising at least one carboxylic acid functional group. The term “organic acid” is further meant to encompass a low molecular weight acid, including a monoacid such as acetic acid and a diacid such as oxalic acid. As used herein, the term “monoacid” is used to denote having one carboxylic acid functional group per molecule. Likewise, the term “diacid” denotes two, and “triacid” denotes three carboxylic acid functional groups per molecule.

The term “reactive fluid,” as used herein, refers to fluid comprising an oxidant that is passed to the kerogen in the subsurface shale formation.

The term “extractive fluid,” as used herein, refers to a fluid that is prepared with additives for mobilizing the organic acid reaction products in the subsurface shale.

The term “aqueous fluid” as used herein refers to any water containing fluid, including pure water, such as, municipal water; surface water, including from a lake, sea, ocean, river, and/or stream; formation water; water associated with industrial activity; or mixtures thereof.

The term “formation water” as used herein refers to the water or aqueous fluid that is naturally occurring in a geological formation, such as the subsurface shale formation, or in a subsurface aquifer. The amount (or presence) of formation water in the formation, and the amount (or presence) of formation water in contact with the kerogen in the formation, depends on a number of factors, including the depth of the subsurface shale formation or the kerogen deposit located therein. In some cases, formation water is present in the formation prior to the start of the process for extracting a kerogen-based product from a subsurface shale formation. The naturally occurring formation water may contain dissolved alkali materials from naturally occurring deposits in the environment of the subsurface shale.

The term “formation fluid” as used herein, is the fluid in contact with the kerogen in the subsurface shale formation. Formation fluid may include the formation water that occurs naturally at, or in the environment of, the subsurface shale. Formation fluid may also include, for example, a fluid (or fluids) that are supplied to the kerogen from the surface. Formation fluid may also include, for example, oxidants, or surfactants, or alkali materials, or mixtures thereof that are supplied from the surface. Formation fluid may also include reaction products from chemical reactions and/or physical absorption processes of the kerogen (and/or bitumen) in the subsurface shale formation.

The term “spent formation fluid,” as used herein, refers to the oxidation activity of the formation fluid, and by extension the concentration of oxidant in the formation fluid. A spent formation fluid has a reduced amount of oxidant, and therefore a reduced oxidation activity toward the conversion of kerogen or products from kerogen conversion. Unless otherwise indicated, a spent formation fluid is one which produces an insignificant amount of reaction products at the temperature of the fluid over the time in which the fluid is withdrawn as a mobile kerogen-based product from the formation.

The terms “natural” or “naturally occurring” refer to conditions existing before, or without, human intervention. Thus, a “natural formation temperature,” as used herein, refers to the temperature of the subsurface shale formation, prior to or in the absence of human intervention with or in the formation. In a specific example, a naturally occurring aqueous fluid may originate from a subterranean aquifer or from a surface body of water, such as a river or stream or from a pond or lake, and that has not been modified by man. In another specific example, a “naturally occurring” aqueous basic solution refers to a solution present in the formation prior to, or in the absence of, human intervention in the formation.

A “surfactant” as used herein refers to any substance that reduces surface tension of a liquid, or reduces interfacial tension between two liquids, or between a liquid and a solid, or facilitates the dispersion of an organic material into an aqueous solution.

The term “basic solution,” as used herein, refers to an aqueous solution having a pH of greater than 7.

The term “acidic solution,” as used herein, refers to an aqueous solution having a pH of less than 7.

A “dense phase fluid,” as defined herein, is a non-gaseous fluid. Such dense phase fluids include liquids, supercritical fluids (SCFs), and fluids at supercritical conditions. The dense phase fluid can be any such fluid that suitably provides for increased accessibility of the kerogen to a fluid—typically due to fracturing and/or rubblizing of the shale in which the kerogen resides.

A “supercritical fluid,” as used herein, is any substance at a temperature and pressure above its thermodynamic critical point. Supercritical fluids can be regarded as “hybrid solvents” with properties between those of gases and liquids, i.e., a solvent with a low viscosity, high diffusion rates and no surface tension. Common supercritical fluids include supercritical carbon dioxide (CO₂) and supercritical water. For example, the critical temperature of CO₂ is 31.1° C., and the critical pressure of CO₂ is 72.9 atm (7.39 MPa).

The term “mechanical stress,” as used herein, refers to structural stresses within the shale formation that result from pressure variations within the formation. Such stress can lead to fracturing and/or rubblization of the shale formation.

The term “thermal stress,” as used herein, refers to structural stresses within the shale formation that result from thermal variations. Such thermal stresses can induce internal mechanical stresses as a result of differences in thermal coefficients of expansion among the various components of the shale formation. Like mechanical stress mentioned above, thermal stress can also lead to fracturing and/or rubblization of the shale formation.

The term “fracturing,” as used herein, refers to the structural degradation of a subsurface shale formation as a result of applied thermal and/or mechanical stress. Such structural degradation generally enhances the permeability of the shale to fluids and increases the accessibility of the kerogen component to such fluids. The term “rubblization,” as used herein, is a more extensive fracturing process yielding fracture planes in multiple directions that generate shale derived “rubble.”

The term “cracking,” as mentioned in the background section and as used herein, refers to the breaking of carbon-carbon bonds in the kerogen so as to yield species of lower molecular weight. “Retorting,” provides thermal cracking of the kerogen. “Upgrading,” provides cracking of the kerogen, but can involve a thermal or chemical upgrading agent. Accordingly, the term “thermal upgrading” is synonymous with the term “retorting.”

Hydrocracking is a chemical reaction of liquid feed materials, including hydrocarbons, petroleum and other biologically derived material, in the presence of hydrogen and one or more catalysts, resulting in product molecules having reduced molecular weight relative to that of the liquid feed materials. Additional reactions, including olefin and aromatic saturation and heteroatom (including oxygen, nitrogen, sulfur and halogen) removal may also occur during hydrocracking.

Pyrolysis temperature, as used herein, is the temperature at which the kerogen thermally decomposes without the intervention of a catalytic or chemical agent.

The term “in situ,” as used herein refers to the environment of the subsurface shale formation.

The term “commercial petroleum-based products,” as used herein, refers to commercial products that include, but are not limited to, gasoline, aviation fuel, diesel, lubricants, petrochemicals, and the like. Such products can also include common chemical intermediates and/or blending feedstocks.

“Optional” or “optionally” means that the subsequently described event or circumstance may, but need not, occur, and that the description includes instances where the event or circumstance occurs and instances in which it does not.

Method Overview

The present invention is generally directed to methods for extracting a kerogen-based product from a subsurface shale formation comprising subsurface shale. The methods include the steps of: providing an oxidant to kerogen in subsurface shale; contacting the kerogen in the subsurface shale with the oxidant at a temperature in the range from 0° C. and 200° C. to form organic acids; and mobilizing at least a portion of the organic acids from the subsurface shale to produce a mobile kerogen-based product.

The step of contacting the kerogen with an oxidant generally involves an in situ chemical modification of the kerogen (e.g., cracking) and/or surrounding shale so as to render the modified kerogen component mobile. Such chemical modification generally involves the making and/or breaking of chemical bonds. In one embodiment, the chemical modification involves the formation of reaction products that contain organic acid and/or organic acid functional groups. At least a portion of these reaction products may be mobilized using an alkaline aqueous solution. The step of transporting the mobile kerogen-based product out of the subsurface shale formation can generally be described as a means of flowing the mobile kerogen-based product out of the subsurface formation, where such a means can be active (e.g., pumping) and/or passive.

In an embodiment, the step of isolating the organic acids from the mobile kerogen-based product involves reducing the relative solubility of the organic acids in the mobile kerogen-based product. One exemplary method involves converting an ionized form of the acid, e.g., a salt of the acid such as a sodium salt, to the corresponding protonated (e.g., non-ionized) form of the acid. In another embodiment, reducing the relative solubility involves contacting the mobile kerogen-based product with a hydrocarbonaceous extractant for extracting at least some of the organic acids from the mobile kerogen-based product to the hydrocarbonaceous extractant. In another embodiment, reducing the relative solubility involves converting the acid to a corresponding ester. In an embodiments, the step of isolating the soluble organic acids involves separating the acids from a carrier fluid by physical means, such as, for example, liquid-liquid separation, distillation, membrane separation, froth flotation, phase separation, electrostatic separation, coalescence, biological processes, thermal separation processes, and steam distillation.

In one embodiment, the above-described method may involve one or more additional steps which serve to sample and subsequently analyze the shale prior to, or in the alternative during, or in the alternative after, performing the step of increasing the accessibility of the kerogen. Such sampling and analysis can have a direct bearing on the techniques employed in the subsequent steps.

In one embodiment, the extracted kerogen-based product is upgraded (thermally and/or chemically) in a surface facility. Such surface upgrading can be intermediate to subsequent refining.

In an illustrative embodiment, a reactive fluid containing at least one reactive component and having a pH of at least 7 is provided to the kerogen in the subsurface shale. The reactive component facilitates cracking reactions in the kerogen, producing mobile organic acid reaction products. The mobile reaction products are absorbed into an aqueous fluid to form a mobile kerogen-based product; the reaction product enriched aqueous fluid is then removed to surface facilities for processing. A reactive fluid may further be provided to the subsurface shale for dissolving or otherwise absorbing mobile reaction products for removal to surface facilities for processing. In another illustrative embodiment, the reactive fluid containing at least one reactive component, and having a pH of less than or equal to 7 is provided to the kerogen in the subsurface shale.

The subsurface shale formation comprises an organic component, at least a portion of which is the kerogen as defined herein. The subsurface shale formation further comprises an inorganic component in addition to the kerogen.

The subsurface shale formation is accessed from the surface through at least one well. In general, the well will be cased, at least for a portion of its distance. Specifications for drilling access wells into a subsurface shale formation are known. In most applications of the invention, multiple wells will be provided into the subsurface shale formation, the well pattern based on recognized principles for this application. In one embodiment, a portion of the wells are employed as injection wells for passing fluids from the surface to the formation, and a portion of the wells are employed as production wells for withdrawing fluids from the formation to the surface. Each of the multiple wells may be used successively as an injection well and a production well, depending on the needs of the process. In an alternative, each well may be prepared and managed optimally as either an injection well or a production well. Specifications of each well for preparing and using the well as an injection well and/or a production well can readily be developed by one of skill in the art.

Conversion Process

The conversion process is a chemical conversion process, with reagents being provided to the kerogen to facilitate the fracture of chemical bonds in the kerogen and between the kerogen and the inorganic matrix in which the kerogen naturally occurs. While the reagents that are provided to convert the shale may be provided as solids, liquids or gases, it has been found that the conversion reactions are facilitated by the introduction of liquid phase materials, or alternatively by using liquid phase materials that are naturally present in the shale formation, for converting the kerogen. Use of liquid phase oxidants during kerogen cracking conversion may advantageously be conducted at liquid phase temperatures, including temperatures in the range from 0° C. to 200° C. The kerogen cracking conversion may advantageously be conducted at formation pressure, or at a pressure sufficiently above formation pressure to permit provision of liquid phase reactants to the kerogen in the oil shale formation.

In one embodiment, the process includes providing an oxidant to kerogen in subsurface shale. Depending on the oxidant, it may be provided in solid, liquid or gaseous form. In liquid form, the oxidant may be provided in acidic, neutral, or alkaline conditions; the choice of pH depends at least in part on the type of oxidant used. Some oxidants are better suited for acidic conditions. For oxidants of this type, the oxidant is provided to the kerogen at a pH in a range from 1.5 to 6.5. Maintaining the pH in this range will generally require the addition of an acidic material to the kerogen. Examples include mineral acids such as hydrochloric acid, sulfuric acid, nitric acid, phosphoric acid and combination Examples s thereof, or organic acids such as one or more of the carboxylic acids having from 2 to 15 carbon atoms, or mixture thereof may be used. With the carboxylic acids, monoacids, diacids, or triacids may be used. In one embodiment, the pH is maintained in a range from 1.5 to 6.5 by provision of CO₂ to the kerogen, alone or in combination with other acids.

Some oxidants are better suited for conditions at neutral pH. Supplying oxidants of this type generally involves supplying the oxidants in combination with a buffered solution, to maintain the pH in the neutral range while contacting the mineral matter within the subsurface shale.

Some oxidants are better suited for alkaline conditions. For oxidants of this type, the oxidant is provided to the kerogen at a pH in a range from 7 to 14, with an embodiment in the range from 7 to 9. Maintaining the pH in the desired alkaline range will be facilitated in some situations by the carbonate and bicarbonate materials that are natural to the subsurface shale formation. Otherwise, the pH in the range from 7 to 14, or in the range from 7 to 9, may be maintained by supply of an alkaline material, such as a carbonate, a bicarbonate, an oxide, a hydroxide, or combinations thereof. In one embodiment, the pH is maintained in a range from 7 to 9 by provision of CO₂ to the kerogen.

In one embodiment, the oxidant is provided to the kerogen in combination with a carrier fluid, the combination being prepared in surface facilities and passed to the subsurface shale through an injection well. Exemplary carrier fluids include an aqueous fluid, an ethanol fluid or combinations thereof. An ethanol fluid contains ethanol, and typically at least 30 wt. % ethanol, such as from 30 wt. % to 100 wt. % ethanol. The ethanol fluid may also contain water. Likewise, the aqueous fluid may contain ethanol. In one embodiment, the carrier fluid encompasses a concentration range from 100 wt. % water to 100 wt. % ethanol, or any combination between.

The carrier fluid generally contains sufficient oxidant to facilitate the production of organic acids from the kerogen in a desired time frame. Higher concentrations of the oxidant generally results in faster reaction rates. In one embodiment, the carrier fluid contains from 0.1 wt. % to 40 wt. % of the oxidant; in another embodiments from 0.1 wt. % to 25 wt. %; in another embodiment from 1 wt. % to 15 wt. %.

The carrier fluid is prepared at a pH that is suited for the particular oxidant used. In one embodiment, the carrier fluid has a pH in the range from 7 to 14; in another embodiment in the range from 7 to 9; in another embodiment in the range from 1.5 to 6.5. Alkaline materials, inorganic acids, organic acids and CO₂ are suitable reagents for the preparation of the carrier fluid at different pH levels.

In one embodiment, the carrier fluid comprises an organic solvent. Illustrative organic solvents that are suitable include refinery streams boiling in the range from 100° C. to 500° C.; C₄ to C₂₁ hydrocarbons, including naphtha, diesel fuel, and gas oils; alcohols, including methanol, ethanol, propanol, butanol; aromatics, including benzene, toluene, the xylenes and alkyl substituted variations thereof; ethers; ketones; esters; tetralin; n-methyl-2-pyrrolidone; tetrahydrofuran; and 2-methyl-tetrahydrofuran. In one embodiment, the formation fluid includes a mixture of an aqueous solvent and an organic solvent, in any proportion.

Oxidant

The process comprises providing an oxidant to kerogen in subsurface shale. The oxidant is selected to be sufficiently stable to be delivered to the kerogen, while maintaining sufficient oxidation activity to facilitate the production of mobile reaction products when in contact with kerogen in the subsurface shale. In one embodiment, the oxidant is selected to be environmentally benign. In one embodiment, the oxidant is selected to minimally impact aqueous aquifers in the region of the kerogen in the subsurface shale. The oxidant may be a single oxidant or an oxidant blend. In one embodiment, the oxidant is selected to be stable in an aqueous fluid which has been prepared to extract, absorb, dissolve or otherwise remove mobile reaction products from the kerogen in the subsurface shale. In one embodiment, the oxidant is selected to react with kerogen to produce a mobile reaction product which contains a high amount (e.g., at least 10 wt. %) of organic acids in the C₃₅+ range.

Exemplary oxidants include Oxone, Oxone combined with one or more manganese porphyrin catalysts, Peracetic Acid, Hydrogen Peroxide, Fenton's reagent, Benzoyl Peroxide, Potassium Permanganate, and combinations thereof.

Oxone is a trade name for potassium peroxymonosulfate (KHSO₅). Oxone is effective as an oxidant for the conversion of kerogen, either alone or in combination with one or more manganese porphyrin catalysts. These oxidants tend to be more stable in acidic solution during long term storage or handling. In one embodiment, oxone or an oxone blend is provided to the kerogen at a pH in the range from 1.5 to 6.5, or in the range from 2.0 to 6.0. When supplying oxone to the kerogen in a basic (i.e., pH>7) solution, care is taken to reduce the natural decomposition of the oxidant. In one embodiment, oxone is provided to the in combination with an oxidation inhibitor, to inhibit the premature decomposition of the oxidant. In one embodiment, oxone is maintained in basic solution in contact with kerogen for the minimum time required to convert kerogen.

Peracetic acid, also known as peroxyacetic acid (CH₃CO₃H), is formed by reacting acetic acid with hydrogen peroxide. It is acidic as prepared, and will generally be provided to the kerogen in acidic solution. In one embodiment, the peracetic acid is provided to the kerogen at a pH in the range from 1.5 to 6.5, or in the range from 2.0 to 6.0.

Hydrogen peroxide (H₂O₂) is typically stable in both acidic and basic solution media. In one embodiment, hydrogen peroxide is provided to the kerogen in pure form, or combined with an amount of inhibitor to prevent premature decomposition of the hydrogen peroxide before contact with kerogen. In one embodiment, the hydrogen peroxide is provided to the kerogen at a pH in the range from 7 to 14; or in the range from 7 to 9. In one embodiment, the hydrogen peroxide is provided to the kerogen at a pH of less than 7; or in the range from 1.5 to 6.5; or in the range from 2.0 to 6.0.

Fenton's reagent is a combination of hydrogen peroxide with an iron (Fe₂+) catalyst. Fenton's reagent may be provided to the kerogen in both acid and alkaline media. In one embodiment, the Fenton's reagent is provided to the kerogen at a pH in the range from 7 to 14; or in the range from 7 to 9. In one embodiment, the Fenton's reagent is provided to the kerogen at a pH of less than 7; or in the range from 1.5 to 6.5; or in the range from 2.0 to 6.0.

Benzoyl peroxide ([C₆H₅C(O)]₂O₂) is minimally soluble in aqueous solution; this oxidant is supplied to the kerogen in either an organic reactive fluid or as a slurry in an aqueous fluid. The slurry may be formed by directly slurrying the benzoyl peroxide into the aqueous fluid; or the benzoyl peroxide is first dissolved in an organic solvent and the solution used to form the slurry.

In one embodiment, the process comprises providing a permanganate oxidant to the kerogen. Permanganate salts that are suitable for the process are readily soluble in aqueous solution, and are stable in basic solutions. This oxidant is effective for producing high amounts of desirable high molecular weight kerogen fragments from kerogen conversion. In one embodiment, the permanganate is provided to the kerogen at a pH in the range from 7 to 14; or in the range from 7 to 9. In one embodiment, the permanganate is provided to the kerogen at a pH of less than 7; or in the range from 1.5 to 6.5; or in the range from 2.0 to 6.0. The permanganate may be any soluble permanganate-containing material. Ammonium permanganate, NH₄MnO₄; calcium permanganate, Ca(MnO₄)₂; potassium permanganate, KMnO₄; and sodium permanganate, NaMnO₄ are suitable permanganates for the process.

Surfactants

In one embodiment, a surfactant or mixture of surfactants are provided to the kerogen in the subsurface shale. The surfactant can be any substance that reduces surface tension of the fluid, or reduces interfacial tension between two liquids, or one liquid and the surrounding formation. The surfactant can also be chosen, for example, to increase the accessibility of the fluid to the kerogen, and/or to increase the mobility of the reaction products from the kerogen, and/or to increase the effectiveness of the fluid for absorbing the reaction products. Suitable surfactants for use in the present fluids may be selected from nonionic, anionic or amphoteric surfactants.

Reactive Fluid

In one embodiment, the oxidant is combined with a solvent or carrier fluid to form a reactive fluid for passing to the kerogen in the subsurface shale formation. The reactive fluid is designed and formulated to provide oxidant to the formation fluid, and to maintain the integrity of the oxidant until it is in contact with the kerogen. In one embodiment, the reactive fluid is further formulated to mobilize organic acids, which are formed during kerogen conversion, either as a suspension of colloidal kerogen fragments or as a solution of dissolved organic acids.

In one embodiment, the reactive fluid includes an aqueous solvent, or an organic solvent, or combinations thereof.

In one embodiment, at least a portion of the reactive fluid is prepared in surface facilities. It may be desirable to locate the preparation of the aqueous reactive fluid such that the prepared fluid is conducted by pipeline transport from the preparation location to the injection well for providing the fluid to the subsurface shale.

The carrier from which the reactive fluid is prepared may be provided from any suitable source, such as, for example, one or more of municipal water; surface water or water from a subsurface aquifer; bitter water sources with high pH levels, and containing quantities of one or more of carbonates, bicarbonates, oxides, and hydroxides, which are recovered from subsurface aquifers; reactive water; and recycle aqueous fluids from the kerogen conversion and extraction process. In one embodiment, the recycle aqueous fluid contains organic acids which remain in solution following the step of isolating at least a portion of the organic acids from the mobile kerogen-based product. In one embodiment, the recycle aqueous fluid contains organic acids from the isolating step that are added back to the recycle aqueous fluid as surfactants. In one such embodiment, the recycle aqueous fluid contains at least 0.1 wt. % organic acids, including, for example, at least 0.5 wt. % organic acids; or at least 1.0 wt. % organic acids.

The oxidant concentration in the reactive fluid is determined by a number of factors, including the stability and reactivity of the oxidant at the conditions of the subsurface formation, the nature of the inorganic component of the subsurface shale, and the desired products from the kerogen conversion reactions. In one embodiment, the oxidant concentration in the reactive fluid is kept at a low level to reduce the secondary oxidation reactions of the organic acids which have been liberated from the kerogen. In one embodiment, the reactive fluid as provided to the subsurface shale formation contains in the range from 0.1 wt. % to 100 wt. % oxidant; or in the range from 0.1 wt. % to 40 wt. % oxidant; or in the range of 0.1 wt. % to 25 wt. % oxidant, or in the range from 1 wt. % to 15 wt. %. In one embodiment, the reactive fluid contains from 0.1 wt. % to 40 wt. % of the oxidant in a carrier fluid selected from the group consisting of an aqueous fluid, an ethanol fluid or combinations thereof.

The pH of the reactive fluid is tailored to the particular oxidant. In one embodiment, the reactive fluid has a pH in a range from 7 to 14; in one embodiment, from 7 to 9. In one embodiment, the reactive fluid has a pH in the range from 1.5 to 7; in one embodiment from 1.5 to 6.5.

In one embodiment, the desired reactive solution pH is achieved with the addition of an acidic material to the reactive solution. Mineral acids, such as hydrochloric acid, nitric acid, sulfuric acid, phosphoric acid or organic acids such as one or more of the carboxylic acids having from 2 to 15 carbon atoms, or mixture thereof may be used. With the carboxylic acids, monoacids, diacids, or triacids may be used.

In one embodiment, the desired reactive solution pH is achieved with the addition of an alkaline material to the reactive solution. Exemplary alkaline materials which are useful include, for example at least one alkaline material selected from carbonates, bicarbonates, oxides, and hydroxides of, for example, sodium, potassium, calcium, and magnesium. An illustrative reactive fluid contains a molar ratio of carbonate to bicarbonate in the range from 5:95 to 95:5; or in the range from 10:90 to 90:10; or in the range from 25:75 to 75:25.

In one embodiment, the reactive fluid comprises a surfactant or mixture of surfactants for provision to the kerogen in the subsurface shale. The surfactant can be any substance that reduces surface tension of the fluid, or reduces interfacial tension between two liquids, or one liquid and the surrounding formation. The surfactant can also be chosen, for example, to increase the accessibility of the fluid to the kerogen, and/or to increase the mobility of the reaction products from the kerogen, and/or to increase the effectiveness of the fluid for absorbing the reaction products. Suitable surfactants for use in the present fluids may be selected from nonionic, anionic or amphoteric surfactants.

In one embodiment, the reactive fluid further comprises at least one phase transfer catalyst to enhance the chemical interaction between kerogen and oxidant, for increasing the reaction rate of the oxidant. In one such embodiment, the phase transfer catalyst is selected from the group consisting of tetraethyl ammonium chloride and the crown ether 1,4,7,10,13,16-hexaoxacyclooctadecane (18-crown-6 crown ether).

Formation Fluid

In the process, kerogen in subsurface shale is contacted with the oxidant. In one embodiment, the oxidant is a gaseous oxidant, and the contacting involves the gas phase oxidant and the solid kerogen. In one embodiment, the oxidant contacts the kerogen in the subsurface shale in liquid medium, otherwise termed a “formation fluid”. In this case, at least a portion of the liquid medium may be the reactive fluid that is prepared in surface facilities and passed to the subsurface shale through an injection well. Likewise, at least a portion of the liquid medium may be formation water that is naturally occurring in the subsurface shale.

In one embodiment, reaction conditions and the composition of the formation fluid for converting kerogen into the mobile kerogen-based product are selected to minimize the environmental effects of the process for extracting the kerogen-based product; and/or to maximize the conversion of kerogen into the mobile kerogen-based product; and/or to maximize the selectivity of the reaction to C₁₀+ organic acids; and/or to minimize the conversion of the kerogen to CO₂.

The step of contacting the kerogen with the formation fluid in the subsurface shale is generally conducted at or near an natural formation temperature. In one embodiment, the contacting occurs at a temperature in the range of between 0° C. and 200° C. In one embodiment, the contacting occurs at a temperature of less than 200° C. above the natural formation temperature. In one embodiment, the contacting occurs at a temperature below a pyrolysis temperature of the kerogen. In one such embodiment, the contacting occurs at a temperature in one the following ranges: between 10° C. and 150° C.; between 20° C. and 100° C.; or between 25° C. and 75° C. In one such embodiment, the formation fluid contacts the kerogen at a temperature of less than 150° C.; or less than 100° C.; or even less than 75° C. above the natural formation temperature. In a non-limiting specific example, the contacting is conducted at a temperature of less than 50° C. above the natural formation temperature. In one embodiment, the contacting is conducted under conditions in which no added heat is supplied to the formation fluid and/or to the subsurface shale in contact with the formation fluid. In one embodiment, if heat is supplied during the kerogen conversion to meet the above-mention target temperature, it is supplied solely from exothermic chemical processes within the kerogen and/or within the subsurface shale in contact with the kerogen. As such, no external heating is provided. The contacting occurs at temperature below pyrolysis temperature of the kerogen.

Generally, the kerogen in the subsurface shale is contacted with the formation fluid at or above natural formation pressure (i.e., the pressure of the subsurface shale formation in the region that includes the kerogen), so as to maintain or increase the accessibility of the fluids to kerogen in the subsurface shale formation. In one such embodiment, the formation fluid is provided to the formation at a pressure above fracture pressure, so as to increase the accessibility of the formation fluid to the kerogen in the formation. Methods for determining the formation pressure and the formation fracture pressure are known. In one such embodiment, the formation fluid is provided to the formation at a pressure of up to 1000 psig; or up to 750 psig; or up to 500 psig; or even up to 250 psig above the natural formation pressure. The natural formation pressure, as used herein, is the pressure of the subsurface shale formation, in the region of the kerogen, prior to human intervention with or in the formation. Methods for determining an natural formation pressure are known.

In one embodiment, the process includes contacting the kerogen in the subsurface shale with an oxidant. The mobile kerogen-based product comprises reaction products from the reaction of the oxidant with the kerogen. The step of creating a mobile kerogen-based product involves a chemical modification of the kerogen. The chemical modification involves at least some cracking of the kerogen, generating smaller kerogen-derived molecules that are correspondingly more mobile.

In one embodiment, a fluid, such as a formation fluid in contact with the kerogen, facilitates the kerogen reactions. The formation fluid may be caused to flow through the subsurface shale formation for an amount of time needed to reach a certain objective, e.g., a reduced oxidant concentration target in the formation fluid, or a target amount of mobile reaction products produced, or a target extent of conversion of the kerogen. The formation fluid may then be caused to flow through the subsurface shale formation for an amount of time need to reach a certain objective, e.g., a target removal of mobile reaction products, or a target concentration of mobile reaction products in the formation fluid. In another embodiment, the process of providing reactive fluid to the kerogen may be a cyclic process, repeated until a target level of kerogen conversion is achieved. In another embodiment, a formation fluid is suitable for both converting kerogen in the subsurface shale and absorbing the reaction products to form the mobile kerogen-based product, which is recovered for isolating the organic acids contained therein.

In one embodiment, pumping is used to transport the mobile kerogen-based product out of the subsurface shale formation, wherein such pumping can be performed using techniques known to those of skill in the art. Conventional oil field practices (both flowing gas and pumping fluids, e.g., rod pumps, electrical submersible pumps, progressive cavity pumps, etc.) can be modified to provide reliability in a given producing environment. For example, modifications may require changes in metallurgy, pressure limitations, elastomeric compositions, temperature rating, and the like.

Production could use any standard producing process such as, but not limited to, at least one well penetrating into the subsurface shale formation as an injection well for providing fluids to the subsurface shale formation and at least one well penetrating into the subsurface shale formation as a production well for producing fluids from the formation, Huff-n-Puff (i.e., a single well is used as both the producer and injector), water flooding, steam flooding, polymer flooding, solvent extraction flooding, thermal processes, diluent addition, steam assisted gravity drainage (SAGD), and the like.

Formation Fluid

The formation fluid is a fluid, such as an aqueous fluid, which is in contact with the kerogen in the subsurface shale formation. In one embodiment, at least a portion of the formation fluid is supplied as a reactive fluid from surface facilities. In one embodiment, the reactive solution provided to the kerogen establishes a formation fluid in contact with the kerogen, or it supplements a formation fluid which is already established, or which is naturally occurring in the subsurface shale formation in contact with the kerogen. In one embodiment, the formation fluid is derived from, or results from, formation water that naturally occurs within the formation. The formation fluid may be present and in contact with the kerogen in the formation, in small quantities which merely wet the solid surfaces in the formation. Alternatively, the formation fluid may be present in sufficient quantities to flood the formation; or in any quantity between the wetted or flooded states.

The formation fluid is any fluid (including mixtures) that can, either by itself, with an agent combined with the fluid, or in combination with a solvent, chemically modify the kerogen so as to render it mobile and therefore extractable. In one embodiment, the formation fluid comprises an oxidant having a chemical property of oxidation. In one aspect, the oxidant is active for breaking chemical bonds in kerogen. In one aspect, the oxidant is active for breaking carbon-oxygen bonds in kerogen. In one aspect, the oxidant is active for breaking carbon-carbon double bonds in kerogen. In one aspect, the oxidant has a low activity for breaking carbon-carbon single bonds in kerogen. In one aspect, the oxidant is active for producing mobile reaction products from kerogen. In one aspect, the oxidant is active for facilitating the mobilization of hydrocarbons from kerogen in subsurface shale.

In one embodiment, at least a portion of the aqueous formation fluid is recovered as a naturally occurring aqueous basic solution from one or more subsurface aquifers; at least a portion of the naturally occurring aqueous basic solution may occur with the subsurface shale. Suitable naturally occurring aqueous basic solutions have a pH of at least 7; or at least 8; or at least 8.5; or in the range of between 7 and 14. In one such embodiment, the naturally occurring aqueous basic solution floods the subsurface shale and is available for absorbing the converted products, or is caused to flow from its source to the subsurface shale that contains the converted products. In another such embodiment, the naturally occurring aqueous basic solution is recovered from the aquifer through a well drilled into the aquifer. The recovered solution, optionally with added components, such as added carbonates, bicarbonates, oxides and/or hydroxides and/or added surfactants, is passed through an injection well into the subsurface shale resource for extracting the hydrocarbon products present therein.

In one embodiment, at least a portion of the alkaline materials, including one or more of carbonates and bicarbonates and oxides and hydroxides, that are present in the formation fluid are derived from naturally occurring deposits. Naturally occurring sources of the alkaline materials are known. The following carbonate and bicarbonate minerals are non-limiting examples.

-   -   Sodium sesquicarbonate (Na₃H(CO₃)₂) is either a double salt of         sodium bicarbonate and sodium carbonate, or an equimolar mixture         of those two salts, with varying quantities of water of         hydration. The dihydrate, Na₃H(CO₃)₂.2H₂O, occurs in nature as         mineral trona.     -   Thermonatrite is a naturally occurring mineral form of sodium         carbonate Na₂CO₃.(H₂O).     -   Natron is a naturally occurring mixture of sodium carbonate         decahydrate (Na₂CO₃.10H₂O) and sodium bicarbonate (NaHCO₃),         often with relatively minor quantities of sodium chloride and         sodium sulfate.     -   Nahcolite is a naturally occurring form of sodium bicarbonate         (NaHCO₃).     -   Shortite is a naturally occurring form of a sodium—calcium         carbonate mineral (Na₂Ca₂(CO₃)₃).

As a non-limiting illustrative example, a reactive fluid is passed, via an injection well, to a source of the alkaline materials within or near the subsurface shale resource to dissolve the alkaline materials into the formation fluid before being passed to the formation fluid in the subsurface shale formation. In some cases, liquid water is injected under sufficient pressure into the carbonate and/or bicarbonate source to cause the water to wet at least a portion of the source and to dissolve at least some of the carbonate and/or bicarbonate into the water.

In one such embodiment, the water that contains the dissolved alkaline materials is caused to flow from the deposit in which it occurs to the subsurface shale resource that contains the converted hydrocarbon products. In another such embodiment, the solution of the dissolved alkaline materials is recovered from the aquifer through a well drilled into the aquifer. The recovered solution, optionally with added components, such as added carbonates, bicarbonates, oxides and/or hydroxides, or added surfactants, is passed through an injection well into the subsurface shale resource for extracting the hydrocarbon products present therein.

In another such embodiment, at least a portion of the water is introduced to the deposit of alkaline materials as steam, and in some cases as superheated steam, to facilitate the dissolution of the alkaline materials into the water. At least some of the steam condenses, dissolves the alkaline materials, and is passed to the subsurface shale formation.

In one such embodiment, the process includes contacting the kerogen with the fresh formation fluid, and producing a spent formation fluid which contains less than 20 wt. %, or less than 10 wt. %, or less than 5 wt. % of the oxidant, or less than 1 wt. % of the oxidant, or less than 0.5 wt. % of the oxidant, or less than 0.1 wt. % of the oxidant. In one embodiment, the reactivity of the formation fluid is enhanced by addition of a combination of oxidants.

The formation fluid has a pH that is generally selected to balance the stability, reactivity and solubility of the oxidant in the formation fluid with the solubility and stability of the kerogen reaction products in the formation fluid. Oxidants that exhibit high kerogen conversion activity in aqueous fluid at pH values of at least 7 are generally supplied to the subsurface shale formation in a basic solution (i.e., basic formation fluid). In one such embodiment, the desired reactive solution pH is achieved with the addition of an alkaline material to the reactive solution. Exemplary alkaline materials which are useful include, for example at least one alkaline material selected from carbonates, bicarbonates, oxides, and hydroxides of, for example, sodium, potassium, calcium, and magnesium. An illustrative formation fluid contains a molar ratio of carbonate to bicarbonate in the range from 5:95 to 95:5; or in the range from 10:90 to 90:10; or in the range from 25:75 to 75:25.

The formation fluid may be further treated with acids or bases to tailor the pH of the formation fluid, to, for example, account for the solubility and/or stability of the oxidant or to increase the solubility of the mobile organic acids produced during the kerogen conversion process. In one embodiment, the formation fluid that is supplied to the subsurface shale has a pH of less than or equal to 7, or in the range from 1.5 to 6.5. In another embodiment, the formation fluid that is supplied to the subsurface shale has a pH of at least 7. In this case, the pH of the formation fluid is selected both to facilitate the solubility of organic acids in the formation fluid and to facilitate the chemical stability and reactivity of the oxidant at subsurface shale formation conditions. In one embodiment, the formation fluid is supplied to the subsurface shale formation at a pH in the range of 7 to 14; or in the range of 7 to 9.

Oxidants that exhibit high kerogen conversion activity in aqueous fluid at pH values of less 7 are generally supplied to the subsurface shale formation in acidic solution (i.e., acidic formation fluid). In one such embodiment, the desired reactive solution pH is achieved with the addition of an acidic material to the reactive solution. Mineral acids, such as hydrochloric acid, nitric acid, sulfuric acid, phosphoric acid or organic acids such as one or more of the carboxylic acids having from 2 to 15 carbon atoms, or mixture thereof may be used. With the carboxylic acids, monoacids, diacids, or triacids may be used. In one embodiment, CO₂ is supplied to the formation fluid, either during preparation, while the fluid is being passed to the kerogen or in contact with the kerogen. When CO₂ is supplied to the formation fluid in the formation, it may be supplied as a subcritical gas, a dense phase gas or a supercritical fluid. In other embodiments, it may be supplied in combination with a liquid fluid. The pH of the prepared formation fluid will generally be selected on the basis of the specific oxidant that is being used. In one embodiment, the pH of an acidic formation fluid will be less than 7, including a pH in the range from 1.5 to 6.5.

The formation fluid may further contain other components for, e.g., enhancing the reactivity of the reactive components, for enhancing the accessibility of the formation fluid to the kerogen, or for enhancing the dissolution, absorption, or dispersion of mobile reaction products into the formation fluid.

Formation Water

Formation water, a naturally occurring liquid source within at least some kerogen deposits in subsurface shale, is a suitable source for at least a portion of the formation fluid used for converting kerogen and recovering useful products. Some kerogen deposits are directly in contact with formation water. Other kerogen deposits are wetted by residual formation water. In other deposits, the formation water aquifer is remote from the kerogen deposit which is being exploited for recovering useful products. When sufficient formation water is present, either in contact with the kerogen or sufficiently near the kerogen deposit to be passed to the kerogen deposit, the formation water may be useful as a source of at least some of the components of the formation fluid.

Certain subsurface shale formations, such as the Green River Shale, are characterized by limestone deposits that produce formation water aquifers having a basic pH (i.e., pH greater than 7). In one embodiment, formation waters are useful as a source or a component of the formation fluid. In an exemplary process, oxidant is provided to formation water to form the formation fluid, which facilitates the conversion of kerogen at a temperature in the range of between 0° C. and 200° C. to form organic acids.

In the case in which the kerogen is naturally in contact with formation water that is suitable for the process, the process includes providing an oxidant to the formation water to produce the formation fluid. For formations in which the formation water having the desired properties is in an aquifer separate from (or remote to) the kerogen, the formation water may be caused to pass from the remote aquifer to the kerogen. This may be achieved, for example, by causing the formation water to pass from the remote aquifer through a borehole which is drilled into the formation water aquifer. In one embodiment, the formation water is passed through the borehole to surface facilities, and processed by addition of oxidant and then provided to the kerogen. In another embodiment, the formation water is passed through the borehole directly to the kerogen in the subsurface shale formation.

When at least a portion of the mobile kerogen-based product is withdrawn from the formation, additional formation fluid in the region of the kerogen is produced by flowing additional formation water to, and contacting, the kerogen in the subsurface shale formation to replace the fluid that was withdrawn. In one embodiment, one or more oxidants are provided to the additional formation water that flows into contact with the kerogen.

As stated, suitable formation water has a pH of at least 7, or in the range from 7 to 14, or in the range from 12 to 14. In one embodiment, the formation water comprises an alkaline material selected from the group consisting of a carbonate, a bicarbonate, an oxide, and a hydroxide. An exemplary alkaline material is selected from the group consisting of sodium carbonate, sodium bicarbonate, and sodium hydroxide, or mixtures thereof.

In the process, a formation fluid which comprises formation water and an oxidant contacts the kerogen for a time sufficient to reduce the oxidant concentration to a target low level. In one embodiment, the formation fluid is caused to contact with kerogen for a time sufficient to reduce the oxidant concentration in the formation fluid to less than 0.5 wt. %, or for a time sufficient to reduce the oxidant concentration in the formation fluid to less than 0.1 wt. %.

Use of formation water as a component of the formation fluid permits the use of a cyclic process to convert kerogen and recover useful products. An exemplary cyclic process comprises the steps of: (a) providing an oxidant to formation water that is in contact with kerogen in subsurface shale to form a formation fluid; (b) contacting the kerogen in the subsurface shale with the formation fluid at a temperature in the range of between 0° C. and 200° C. to form organic acids; (c) recovering at least a portion of the organic acids from the subsurface shale formation to form a mobile kerogen-based product; (d) withdrawing at least a portion of the mobile kerogen-based product from the formation; (e) providing additional oxidant to the formation water in contact with the kerogen; and (f) repeating steps (b), (c), (d), and (e) a multiplicity of cycles, and converting at least 50 wt. % of the kerogen to organic acids. In one embodiment, the cyclic process also includes recycle steps, including: isolating at least a portion of the organic acids from the mobile kerogen-based product; recovering an organic acid lean aqueous fluid; and providing at least a portion of the organic acid lean aqueous fluid, in combination with added oxidant, to the formation fluid in contact with the kerogen.

Organic Acids

In the process, the oxidant contacts the kerogen to form organic acids. The organic acids may be saturated, unsaturated, or polyunsaturated. In one embodiment, at least a portion of the organic acids are branched; the branching functional groups may be paraffinic, olefinic or cyclic. Cyclic branching functional groups may be saturated, unsaturated or aromatic. The organic acids may also contain nitrogen and/or sulfur atoms. In one embodiment, the organic acids are monoacids (a single carboxyl functional group in non-ionized or ionized form per molecular unit), or diacids (two carboxyl functional groups per molecular unit), or triacids (three carboxyl functional groups per molecular unit), or higher. Mobile kerogen fragments, including kerogen fragments having a molecular mass of up to 12,000 to 15,000 Daltons or higher, may have multiple carboxyl functional groups that serve to render these fragments mobile in an aqueous medium. These high molecular weight fragments are generally mobilized in the fluid as a slurry, rather than as a pure solution. Under some conditions, the organic acids are present as salts. An exemplary sodium salt of an organic acid contains the carboxyl function group represented by —COO—Na+.

The molecular weight of the organic acids covers a very wide range, including from low molecular weight acids, such as the monoacid, acetic acid, and the diacid, oxalic acid, to high molecular weight kerogen fragments, having a molecular mass of up to 15,000 daltons or higher, and comprising at least one carboxylic acid functional group. In one embodiment, these kerogen fragments have a lower molecular mass than the naturally occurring kerogen itself, but with the general characteristic chemical and conformational complexity of the kerogen structures from which they are derived. Such high molecular weight acids are soluble in, or otherwise mobile in, high pH solutions, such as solutions having a pH of at least 7; or at least 8; or at least 8; or in the range of between 12 and 14. Accordingly, in one embodiment, at least 10 wt. %, or at least 30 wt. %, or at least 50 wt. % of the organic acids in the mobile kerogen-based product is in the C₃₅+ range. In one embodiment, at least 20 wt. % of the C₃₅+ organic acids has a molecular mass number of greater than 1000 daltons.

In one embodiment, a significant fraction of the organic acids are also in the C₆ to C₂₀ carbon number range. In one such embodiment, at least 10 wt. % of the organic acids in the mobile kerogen-based product are in the C₆ to C₂₀ range, or in the C₆ to C₁₆ range, or in the C₈ to C₁₄ range or in the C₈ to C₁₂ range. In one such embodiment, at least 20 wt. % of the C₃₅− organic acids is in the C₈ to C₁₂ range. Maintaining reaction conditions to minimize the amount of oxidation of the kerogen while ensuring that the reaction products are mobile has the benefit of decreased oxidant consumption, minimum formation of carbon dioxide product, and reduced hydrogen consumption during the hydrogenation of the acid products during an upgrading step.

In general, the mobile kerogen-based product contains at least one of the following organic acids and hydrocarbons: monoacids, diacids, branched monoacids, branched diacids, isoprenoid acids, iopanoic acids, gamma keto acids, keto monoacids, keto diacids, and n-alkanes. In the range from 10 wt. % to 90 wt. % of the C₃₅− organic acids in the mobile kerogen-based product are monoacids. In one such embodiment, in the range from 10 wt. % to 50 wt. % of the C₃₅− organic acids are monoacids. Likewise, in the range from 10 wt. % to 90 wt. % of the C₃₅− organic acids in the mobile kerogen-based product are diacids. In one embodiment, at least 30 wt. % of the C₃₅− organic acids are diacids. In one such embodiment, in the range from 30 wt. to 90 wt. % of the C₃₅− organic acids are diacids. In one embodiment, in the range from 1 wt. % to 30 wt. %, or in the range from 1 wt. % to 20 wt. %, or in the range from 1 wt. % to 10 wt. % of the C₃₅− organic acids in the mobile kerogen-based product are gamma keto acids.

Mobile Kerogen-Based Product

In one embodiment, the organic acids are mobilized to produce a mobile kerogen-based product. The mobile kerogen-based product generally contains at least 1 wt. % organic acid derived products; or at least 2 wt. % organic acid derived products; or at least 5 wt. % organic acid derived products. In some situations, the organic acid derived products are present in the product at a concentration in the range from 5 wt. % to 50 wt. %; or at a concentration in the range from 10 wt. % to 40 wt. %. The ratio of organic acid derived products to other hydrocarbons in the mobile kerogen-based product will depend on the source of the hydrocarbons, but is expected to range from 10% organic acid derived products to 100 wt. % organic acid derived products.

It is believed that organic acids comprise a significant portion of the kerogen based product formed from reaction of oxidants on the kerogen. However, when the organic acids are mobilized, organic acid reaction products may be involved. As such, mobilization of the organic acids may involve, for example, neutralization, dimerization and esterification of the organic acids.

Thus, in one embodiment, the mobile kerogen-based product may comprise organic acid as organic acids. In one embodiment, the mobile kerogen based product may comprise organic acids as organic acid anionic moieties (RCOO—) or organic acid salts (RCOO-M+). The cation (M+) of the organic acid salts can be cations that are naturally present in the formation, for example, sodium, potassium, calcium and magnesium. In one embodiment, the mobile kerogen based product may comprise organic acids as esters. Exemplary esters include methyl and ethyl esters. In one embodiment, the mobile kerogen-based product may comprise organic acids in a form selected from the group consisting of organic acids, organic acid salts, anionic organic acid moieties, organic acid esters, and mixtures thereof.

The mobile kerogen-based product may further include components to facilitate extraction of reaction products from the kerogen. These components may include, for example, one or more of a solvent or solvent mixture; alkaline materials; surfactants; organic and/or inorganic acids; organic and/or inorganic bases; soluble organic compounds such as alcohols, ethers, esters, ketones, aldehydes, and the like. In one embodiment, the mobile kerogen-based product is an aqueous phase fluid containing the organic acid derived products, which are dissolved, dispersed, or suspended in the aqueous phase fluid.

As used herein, the term “mobile kerogen-based product” refers to the fluid containing the mobile reaction products that is withdrawn from the formation. The mobile kerogen-based product is formulated to keep the mobile reaction products in a mobile phase by, for example, maintaining the pH of the mobile kerogen-based product at or above a target minimum level. In one embodiment, the mobile kerogen-based product contains at least one surfactant to further stabilize the reaction products as they are withdrawn from the formation. The mobile kerogen-based product may contain residual oxidants; however, withdrawing the mobile reaction products after reacting and/or removing most or all of the active oxidant serves to minimize the secondary oxidation reactions of the mobile reaction products.

In one embodiment, the mobile kerogen-based product further comprises hydrocarbons other than organic acids. These hydrocarbons include extractible organic components which are present in the subsurface shale and may also be mobilized in the mobile kerogen-based product. This hydrocarbon fraction consists of both aliphatic and aromatic components. The aliphatic component can further be divided into acyclic alkanes, referred to as paraffins, and cycloalkanes, referred to as naphthenes. The lightest hydrocarbons, such as methane and ethane, are gases at room temperature and pressure; heavier hydrocarbons are liquids whose viscosity increases with the number of carbons. At least a portion of these hydrocarbons are soluble in carbon disulfide.

In general, little or no active oxidant remains in the mobile kerogen-based product. The oxidant concentration in the mobile kerogen-based product is sufficiently low to minimize or to prevent additional oxidation reactions of the mobile reaction products in the fluid. In an embodiment, the mobile kerogen-based product contains less than 0.5 wt. % of an oxidant. In an embodiment, the mobile kerogen-based product contains less than 0.1 wt. % oxidant. In an embodiment, the mobile kerogen-based product contains an amount of oxidant that is below the detection limit for that oxidant.

In one embodiment, the mobile kerogen-based product further includes a carrier fluid, which may be an aqueous carrier fluid, an organic carrier fluid, or a combination of the two. In one embodiment, the carrier fluid includes one or more components of a recycle fluid from the process. In one embodiment, the carrier fluid contains naturally occurring formation water which has a pH in the suitable range. In a further embodiment, the formation water contains alkaline materials which have been dissolved into the formation water from alkaline sources, such as nahcolite, within the formation.

In one embodiment, the organic acid reaction products are mobilized at a pH of at least 7, or at a pH in a range from 7 to 14. The pH of the mobile kerogen-based product into which organic acids are extracted, following conversion of the kerogen, may, under some conditions, have a pH in a range from 7 to 14 by reason of contact with alkaline materials in the subsurface shale. Alternatively, at least a portion of the alkaline materials present in mobile product may be provided from surface facilities. Exemplary alkaline materials which are useful include, for example at least one alkaline material selected from carbonates, bicarbonates, oxides and hydroxides of, for example, sodium, potassium, calcium, and magnesium. In an illustrative process, organic acids are extracted from kerogen in contact with alkaline materials, such that a molar ratio of carbonate to bicarbonate in the range from 5:95 to 95:5; or in the range from 10:90 to 90:10; or in the range from 25:75 to 75:25.

The pH of the mobile fluid in contact with the kerogen, for extracting organic acid reaction products, is tailored for the particular organic acids to be extracted into and absorbed by the mobile product. Low molecular weight acids are soluble in fluids having a pH at or near the neutral range (i.e. a pH in a range from 6 to 8). High molecular weight kerogen fragments may be mobilized as a colloid or slurry in the mobile product at a pH in a range from 12 to 14.

Formation of the mobile kerogen-based product may be facilitated by the presence of one or more organic solvents. Suitable organic solvents are selected to remain in a liquid phase, and to maintain the reaction products in solution, at temperature and pressure conditions within the subsurface shale. In one embodiment, a suitable organic extraction fluid is one in which at least a portion of the organic acids are soluble. Exemplary organic extraction fluids contain aromatic compounds such as benzene, toluene and xylene; nitrogen containing solvents such as NMP, amines, and amides; oxygenates containing compounds such as acids, ketones, esters and aldehydes; paraffins and naphthenes; olefins and the like. Illustrative organic solvents include refinery streams boiling in the range from 100° C. to 500° C., such as diesel fuel or naphtha.

In one embodiment, the mobile kerogen-based product may include carbon disulfide. Hydrogen sulfide, in addition to other sulfur compounds produced from the formation, may be converted to carbon disulfide using known methods. Suitable methods may include oxidation reaction of the sulfur compound to sulfur and/or sulfur dioxides, and by reaction of sulfur and/or sulfur dioxides with carbon and/or a carbon containing compound to form the carbon disulfide formulation.

Product Recovery

The step of extracting and absorbing the organic acid reaction products into the mobile kerogen-based product fluid is generally conducted at or near the natural formation temperature. In one such embodiment, the absorbing is conducted at a temperature of less than 200° C.; or less then 150° C.; or less than 100° C.; or even less than 75° C. above the natural formation temperature. In one such embodiment, the absorbing is conducted at a temperature in the range of between 0° C. and 200° C.; or in the range of between 10° C. and 150° C.; or in the range of between 20° C. and 100° C.; or even in the range of between 25° C. and 75° C. In a non-limiting specific example, the absorbing is conducted at a temperature of no greater than 50° C. above the natural formation temperature.

In one embodiment, the absorbing is conducted under conditions in which no added heat is supplied to the formation fluid and/or to the subsurface shale in contact with the formation fluid. In one embodiment, if heat is supplied during the kerogen conversion to meet the above-mention target temperature, it is supplied solely from exothermic chemical processes within the kerogen and/or within the subsurface shale in contact with the kerogen. In one embodiment, the absorbing is conducted at a temperature below pyrolysis temperature.

Generally, the organic acids in the subsurface shale are absorbed into the mobile kerogen-based product at or above formation pressure (i.e., the pressure of the subsurface shale formation in the region that includes the kerogen), so as to maintain or increase the accessibility of the fluids to kerogen in the subsurface shale formation. In one embodiment, the organic acid reaction products are extracted from the kerogen and into the mobile kerogen-based product at a pressure of up to 1000 psig above the formation pressure; or up to 750 psig above the formation pressure; or up to 500 psig above the formation pressure; or even up to 250 psig above the formation pressure. Injection of a gas into the formation may result in a viscosity reduction of some of the hydrocarbon products in the formation.

In one embodiment, a formation fluid is maintained in contact with the kerogen until a target amount of mobile reaction products have been absorbed by the formation fluid, i.e., for a time sufficient to produce a mobile kerogen-based product which contains at least 1 wt. % organic acids; or at least 2 wt. % organic acids; or at least 5 wt. % organic acids. Progress toward reaching the target amount may be monitored, for example, by withdrawing the fluids to the surface for analysis, by analyzing the fluids in the subsurface shale formation, or by analyzing the fluids in a well extending into the formation.

In one embodiment, a formation fluid that is suitable for mobilizing the reaction products has a pH of greater than a target value, e.g., greater than 7, and the formation fluid is maintained in contact with the kerogen for a time during which the pH of the formation fluid remains higher than the target minimum pH value. When the pH approaches or drops below the target minimum, the formation fluid may be removed from the subsurface shale, its alkaline content may be supplemented with alkaline additives, or it may be supplemented with added reactive fluid.

In an exemplary process illustrated in FIG. 1, a reactive fluid is prepared in a preparation step 10 by mixing an oxidant 2 with a carrier fluid 4, which may be aqueous or organic. Mixing devices for mixing the oxidant with the carrier fluid to make the reactive fluid are well known. In one embodiment, the oxidant that is used is effective for reacting with kerogen in an alkaline medium; under these conditions the fluid may optionally be mixed with an alkaline material 6 to result in a fluid having a pH of at least 7.

The reactive fluid mixture 15 is passed to the kerogen in the subsurface shale formation in step 20 via a first (e.g., injection) well that has been drilled to penetrate the subsurface formation to provide access to the kerogen within the formation. The reactive fluid combines with a fluid already present to form a formation fluid 25, in contact with the kerogen. In one embodiment, the subsurface shale formation has been fractured to enhance the permeability of the shale to the oxidant and to increase the accessibility of the kerogen component to this fluid. In step 30 the oxidant reacts with the kerogen to produce a mobile kerogen-based product 35, which is produced to the surface in step 40. In one embodiment, multiple reactive fluid batches are provided to the formation fluid, prior to recovery of the mobile kerogen-based product. The timing of each reactive fluid addition depends, at least in part, on the progress of the kerogen conversion, and on the relative reactivity of the formation fluid in contact with the kerogen. For example, another reactive fluid batch may be provided to the formation fluid when the oxidant concentration in the formation fluid falls below 30 wt. %, or below 20 wt., or below 10 wt. % of the initial oxidant concentration in the fluid.

The mobile kerogen-based product 45 produced at the surface is treated in step 50 for isolation and recovery of the organic acids and other mobile hydrocarbons 75. In one embodiment, at least a portion of the reaction products recovered from the kerogen conversion is absorbed by naturally occurring alkaline enriched water that is present in the subsurface shale. In the illustrative process shown in FIG. 1, the organic acids 75 isolated in step 50 are subjected to further processing in step 70. In an embodiment of the illustrative process, an organic acid lean fluid 55 that is produced from the isolation step 50 is further treated in step 80 for recycle 85 to the subsurface shale formation.

In an exemplary process illustrated in FIG. 2, and with further reference to the descriptions above relating to FIG. 1, a mobile kerogen-based product 35 is produced to the surface in step 40. The mobile kerogen-based product 45 produced at the surface is combined with an organic extraction fluid 115 and the combination treated in step 50 for isolation and recovery of the organic acids and other mobile hydrocarbons 75. The organic acids 75 isolated in step 50 are subjected to further processing in step 70. In an embodiment of the illustrative process, an organic acid lean fluid 55 that is produced from the isolation step 50 is further treated in step 80 for recycle 85 to the subsurface shale formation. An acid lean extractant 105 from step 50 is recycled and combined with organic extraction fluid 115.

In an exemplary process illustrated in FIG. 3, a reactive fluid 115 is prepared in a preparation step 110 by mixing an oxidant 102 with a carrier fluid 104, which may be aqueous or organic. Mixing devices for mixing the oxidant with the carrier fluid to make the reactive fluid are well known. In one embodiment, the oxidant that is used is effective for reacting with kerogen in an alkaline medium; under these conditions the fluid may optionally be mixed with an alkaline material 106 to result in a fluid having a pH of at least 7.

The reactive fluid mixture 115 is passed to the kerogen in the subsurface shale formation in step 120 via a first (e.g., injection) well that has been drilled to penetrate the subsurface formation to provide access to the kerogen within the formation. The reactive fluid combines with a fluid already present to form a formation fluid 125, in contact with the kerogen. In one embodiment, the subsurface shale formation has been fractured to enhance the permeability of the shale to the formation fluid and to increase the accessibility of the kerogen component to this fluid. In step 130, the oxidant reacts with the kerogen to form organic acids 135.

A extractive fluid 145 is prepared in preparation step 140 by mixing an alkaline material 142 with an aqueous carrier fluid 144 and optionally with a surfactant 146. The extractive fluid 145 is combined into the formation fluid in step 150 for mobilizing the organic acids and to form the mobile kerogen-based product 155, which is recovered. The mobile kerogen-based product 155 is treated in 160 to isolate organic acids 175, which may be further processed in 170.

Isolating the organic acids further produces an organic acid lean fluid 165, containing a reduced amount of organic acids. This fluid is prepared for return to the formation as a recycle fluid 185. Prior to recycling, the organic acid lean fluid may be conditioned in step 180 for recycling to the formation. Typical conditioning steps include, for example, removing inorganic salts, removing at least a portion of the remaining organic acids, including C₁ to C₁₀ organic acids, and removing other organic material from the fluid.

During some applications of the process, it may be desirable to contact kerogen in the subsurface shale with multiple oxidant treatments. With each treatment, an oxidant or a reactive fluid containing the oxidant is provided to the kerogen, for contacting the kerogen for a time sufficient to reduce the amount of oxidant to a target low level. Reaction products, including organic acids from the oxidation of kerogen, are mobilized by extracting, dissolving, absorbing or otherwise dispersing these products into an alkaline containing mobile kerogen-based product having a pH of at least 7. In one embodiment, the removal of reaction products following the first oxidation treatment is facilitated by the presence of alkaline materials in the formation fluid, provided, for example, by supplying the alkaline materials to the formation fluid, by providing alkaline formation water to the formation fluid, or by adding a reactive fluid containing the alkaline material to the formation fluid.

Following removal of the mobilized reaction products in the mobile kerogen-based product, a second treatment of oxidant is supplied to the formation fluid in contact with the kerogen. As with the first treatment, the oxidant may be supplied in pure form, or dissolved or otherwise associated with a carrier fluid, such as an aqueous carrier fluid, in a reactive fluid. The oxidant used in the first and second treatments may be the same or different. In one embodiment, the oxidants used in the first and second treatments are the same. Likewise, the concentration of the oxidant in the first treatment and the second treatment may be the same or different. Following the second treatment, additional mobilized reaction products are removed from the subsurface shale formation in a mobile kerogen-based product. In one embodiment, the removal of reaction products following the second oxidation treatment is facilitated by the presence of alkaline materials in the formation fluid, provided, for example, by supplying the alkaline materials to the formation fluid, by providing alkaline formation water to the formation fluid, or by adding a reactive fluid containing the alkaline material to the formation fluid. In another embodiment, the kerogen is contacted with multiple oxidant treatments, which is followed by removal of a mobile kerogen-based product containing at least a portion of the organic acids formed in the multiple treatments.

Generally sufficient oxidant is supplied to the formation fluid to result in a formation fluid containing in the range of 0.1 wt. % to 40 wt. % oxidant. In one embodiment, sufficient oxidant is supplied to result a fluid containing in the range of 0.1 wt. % to 25 wt. %; or in the range of 1 wt. % to 15 wt. % of the oxidant. Generally, at least 50 wt. % of the oxidant is consumed during each treatment. In some embodiments, at least 60 wt. %, or at least 70 wt. %, or at least 80 wt. % of the oxidant is consumed during each treatment. Generally, at least 30 wt. % of the kerogen is converted during the multiple treatment process. In one embodiment, at least 50 wt. %, or at least 60 wt. %, or at least 70 wt. % of the kerogen is converted during the multiple treatment process.

In one embodiment, the process for extracting a kerogen-based product includes causing the mobile kerogen-based product to flow through the subsurface shale formation and to a second (e.g., production) well that has been drilled to penetrate the subsurface formation to withdraw fluids from the formation. The formation fluid in contact with the kerogen causes some of the kerogen to react and form mobile reaction products, which are recovered from the subsurface shale to surface facilities for isolation and recovery of the mobile reaction products. In one embodiment, at least a portion of the mobile reaction products are absorbed by the formation fluid and the resulting mobile kerogen-based product is recovered from the subsurface shale formation.

In one embodiment, the reactive fluid is caused to flow into the subsurface shale formation from the injection well until a target pressure higher than formation pressure is reached within the formation. The flow of the reactive fluid is then slowed or stopped and the resultant formation fluid mixture is maintained in contact with the kerogen, while converting kerogen in the subsurface shale to a mobile kerogen-based product and producing an oxidant-depleted formation fluid. At least a portion of the formation fluid mixture may be removed from the kerogen when, for example, the reactivity of the formation fluid is depleted below a target amount, or the pH of the formation fluid has changed beyond a target pH range, or the amount of reaction products from kerogen conversion which has been absorbed by the formation fluid has met or exceeded a target amount. Alternatively, additional oxidant may be provided to the formation fluid, or the oxidant may be regenerated in situ. In one embodiment, the mobile kerogen-based product is at least partially removed from the subsurface shale by reducing the pressure on the shale and permitting the formation fluid to flow into a well for removal to the surface. In one embodiment, the mobile kerogen-based product is at least partially removed by displacement with additional reactive fluid added to the formation through an injection well.

In one embodiment, oxidant is maintained in contact with the kerogen until a target amount of mobile reaction products are produced and/or are absorbed into the formation fluid. Progress toward reaching the target amount may be monitored, for example, by withdrawing the fluids to the surface for analysis, by analyzing the fluids in the subsurface shale formation, or by analyzing the fluids in a well extending into the formation. In one embodiment, the formation fluid is maintained in contact with the kerogen up to a target kerogen conversion. In one such embodiment, the formation fluid is maintained in contact with the kerogen until at least 10 wt. %; or at least 30 wt. %; or at least 50 wt. %; or at least 60 wt. %; or at least 70 wt. %; or even at least 80 wt. % of the kerogen is converted to mobile reaction products. In one embodiment, the formation fluid is maintained in contact with the kerogen for a time sufficient to reduce the concentration of the oxidant to a target value. Reducing oxidant concentration to low levels during reaction facilitates the formation of high amounts of large mobile kerogen fragments and the formation of low amounts of CO₂ during reaction of the kerogen. For example, less than 15 wt. %; or less than 10 wt. %; or less than 5 wt. % of the kerogen is converted to CO₂ during reaction with the formation fluid. In one embodiment, the formation fluid is maintained in contact with the kerogen for a period of greater than 1 hour; or in another embodiment for a period of greater than 4 hours, or for a period of greater than 12 hours. In another embodiment, the formation fluid is maintained in contact with the kerogen for a period in the range from 1 hour to 45 days; in another embodiment from 12 hours to 20 days; in another embodiment from 1 day to 7 days, in order to reduce the concentration of the oxidant to a target value in the spent formation fluid.

The process may further include monitoring the extent of reaction of the kerogen. For example, a fluid sample, such as the formation fluid, may be removed from the subsurface shale formation and analyzed for the oxidant component. Alternatively, the progress of the reaction may be monitored using a downhole analyzer to determine the concentration of the oxidant component in the formation fluid. An analyzer suited to determining a quantity of the oxidant may be inserted into, or intimately contacted with the fluids in the subsurface shale formation.

In other embodiments, the process further comprises monitoring the kerogen conversion using the amount of mobile reaction products in the subsurface shale formation. As with the oxidant reactive component described above, the amount of mobile reaction products may be determined from an analysis of fluids recovered from the formation, or from a downhole analysis tool suited for analyzing the amount of reaction products.

In an embodiment, additives are supplied to the formation fluid in the subsurface shale formation to further the reactivity of the formation fluid mixture and/or to facilitate the formation of the mobile kerogen-based product. In one such embodiment, additional oxidants may be supplied from surface facilities through the one or more injection wells provided for supplying fluids to the kerogen. The oxidant additive may be the same as the oxidant in the formation fluid, or different. In general, the selection of the oxidant additive and the target increase in reactivity of the formation fluid after treatment with the oxidant additive depends on a number of factors relating to the formation and the kerogen within the formation. For example, an oxidant additive may be supplied to the formation fluid to maintain a low reactivity of the formation fluid, to facilitate the formation of large kerogen fragments in the mobile kerogen-based product, rather than light acids or CO₂. In a non-limiting example, an oxidant concentration in the range from 1 wt. % to 15 wt. % is maintained through the reaction phase, with additional oxidant being supplied to the formation fluid to maintain a concentration within this range.

In one embodiment, CO₂ is supplied as an additive to the shale formation during the reaction step to control the pH of the formation fluid mixture. The additive CO₂ may be injected into the shale formation as a pressurized gas or as a supercritical fluid, depending, at least in part, on the formation pressure in the vicinity of the kerogen.

In one embodiment, depending on the conditions and formation fluids employed and on the kerogen bonds that are broken, it is possible to generate a mobile kerogen-based product that is tailored so as to minimize recovery of heavy metals and/or other undesirable materials, or to increase recovery by reducing char and/or other carbon residues. Accordingly, it is possible to generate a mobile kerogen-based product that requires little or no additional refining.

Trona Water

In one embodiment, organic acids occur in naturally occurring aqueous fluids. Most of these naturally occurring aqueous fluids are subterranean; they can be recovered by penetrating the aquifer with a well and pumping the aqueous fluid to the surface for isolation and upgrading of the organic acids contained therein. While the source of the organic acids in the naturally occurring aqueous fluids has not been specifically identified, it is believed that at least a portion of the organic acids are derived from the conversion of subterranean kerogen over geological timeframes. These naturally occurring aqueous solutions that contain significant organic acids contents are known by a number of different names. The term “Trona water” is frequently applied at least one source.

The naturally occurring aqueous fluid is water based, with substantial quantities of organic acids, which are stabilized in the fluid by high fluid pH. In one embodiment, the naturally occurring aqueous fluid is recovered from an underground reservoir or aquifer, or from a lake, river or body of water which is supplied from an underground reservoir or aquifer. In general, the naturally occurring aqueous fluid is recovered from a natural source as a liquid phase solution, or as a slurry, suspension or emulsion.

In producing a naturally occurring aqueous solution, in one embodiment, the producing step includes recovering an aqueous fluid from a body of water, such as stream, a river, a lake, or a pond. In one such embodiment, the water in the body of water originates from a subterranean reservoir. In a further embodiment, the producing step includes recovering the naturally occurring aqueous fluid directly from a subterranean reservoir through a well penetrating the earth to the subterranean reservoir. Methods for producing the well, preparing the well for recovery of liquids and recovering liquids such as aqueous fluids from a subterranean reservoir are well known. In one embodiment, the produced aqueous fluid, either from a surface body of water or from a subterranean reservoir, is treated as described herein to isolate the organic acids contained therein.

These organic acids may be present in the aqueous fluid at a concentration of greater than 1 wt %. In some situations, the organic acids are present at a concentration of greater than 2 wt. % or even 5 wt. %. In some situations, the organic acids are present at a concentration in the range of from 1 wt. % to 50 wt. %, or from 1 wt. % to 40 wt. %, or from 1 wt. % to 30 wt. %. The ratio of organic acids to other hydrocarbons in the aqueous fluid will depend on the source of the hydrocarbons, but is expected to range from 10% organic acids to approaching 100 wt. % organic acids, with at most measurably trace amounts of other functional types.

In one embodiment, the aqueous fluid contains one or a mixture of inorganic components. In one such embodiment, at least one of the inorganic components contributes to increasing the solubility of the hydrocarbon component in the aqueous solution. For example, the solubility of organic acids in the aqueous solution may be enhanced by inorganic components that are alkaline in aqueous solution. In embodiments, the aqueous fluid has a pH of at least 7, or at least 8, or at least 8.5, or in the range of between 7 and 14. In one embodiment, the aqueous fluid pH is achieved with the presence of an alkaline material to the aqueous solution. Exemplary alkaline materials include, for example at least one alkaline material selected from carbonates, bicarbonates, oxides, and hydroxides of, for example, sodium, potassium, calcium, and magnesium. In one embodiment, the aqueous fluid comprises an alkaline material selected from the group consisting of sodium carbonate, sodium bicarbonate, and sodium hydroxide. At least a portion of the alkaline material may be in the form of carbonate and/or bicarbonate minerals. In an illustrative process, organic acids are extracted from kerogen in contact with alkaline materials, such that a molar ratio of carbonate to bicarbonate in the range from 5:95 to 95:5; or in the range from 10:90 to 90:10; or in the range from 25:75 to 75:25.

The organic acids are isolated from the mobile kerogen-based product in surface facilities. In one embodiment, isolating the organic acids involves one or more of pH titration, fractional neutralization, esterification, extraction, distillation, membrane separation, froth flotation, phase separation, electrostatic separation, filtering, centrifugal separation, coalescence, precipitation, thermal separation, steam distillation, or any combination thereof, in any order.

Reducing the pH of the mobile kerogen-based product generally involves adding an acid to the product. Suitable acids for this step include the mineral acids, such as sulfuric acid, hydrochloric acid, nitric acid, phosphoric acid or mixtures thereof. In one embodiment, addition of CO₂ to the mobile kerogen-based product lowers the pH sufficiently to produce a second phase of the high molecular weight organic acids, which may be liquid or solid. In one embodiment, sufficient acid is added to the mobile kerogen-based product to reduce the pH of the product to a pH in a range from 7 to 12; in another embodiment to less than 7; in another embodiment in a range from 1.5 to 7; and in another embodiment in a range from 1.5 to 6.5. In one embodiment, the pH is lowered to a pH in the range from 9 to 12 to isolate C₃₅+ organic acids, some of which at least are solid C₃₅+ organic acids. In another embodiment, the pH is lowered in a single step to a pH in a range from 1.5 to 6.5, to produce an organic acid syncrude comprising organic acids in the C₁₂+ range. In other embodiments, the pH is lowered in multiple steps, with organic acid products being isolated and recovered after each step.

In one embodiment, after each change in pH, at least a portion of the organic acids that form a separate liquid or solid phase from the mobile kerogen-based product is isolated. In one embodiment, the mobile kerogen-based product is contacted with an organic extraction fluid either before, during or after the pH change, for extracting at least a portion of the acids from the mobile kerogen-based product into the organic extraction fluid.

The amount of acid that is added is controlled by a number of factors that are specific to the particular process, including the target pH of the acidified product, the chemical character of the dissolved organic acids and the composition of the product prior to an acidification step. For example, a mobile kerogen-based product that contains a carbonate/bicarbonate mixture in a buffering effective amount will generally require a greater amount of acid for acidifying the fluid. Acidifying conditions may include, for example, a temperature in the range from 0° C. to 200° C.; or in the range from 10° C. to 150° C.; or in the range from 20° C. to 100° C.; or even in the range from 25° C. to 75° C.

During pH titration, the non-ionized organic acids which are formed are less soluble in the aqueous mobile kerogen-based product than are the ionized organic acids; these relatively insoluble organic acids form a separate liquid phase from the kerogen-based product, and may be isolated from the product using conventional liquid-liquid separation methods.

High molecular weight organic acids, including kerogen fragments that form either an emulsion or a solution in highly alkaline aqueous fluids, may be separated from the aqueous fluids at pH values of at least 7. Under these conditions, gaseous CO₂ that is provided to the mobile kerogen-based product is adequate for reducing the pH such that these high molecular weight organic acids separate from the mobile kerogen-based product as a separate liquid, or solid, phase. In one embodiment, at least a portion of the gaseous CO₂ used for pH titration is recovered from a decarboxylation process or from the pH titration process.

In one embodiment, the process of isolating organic acids is modified to facilitate the separation of product organic acids. Fractional neutralization is an example of such a process. During fractional neutralization, the mobile kerogen-based product is treated in sequential steps; the treatment process converts increasingly larger amounts of relatively more soluble ionized organic acids to relatively more insoluble non-ionized organic acids. The organic acids which are isolated during each stage of the fractional neutralization process are characterized by a particular set of chemical and physical properties, such as molecular weight, number of carboxylate groups per molecule, and the olefinicity of the organic acids. In an illustrative example of a fractional neutralization process, a mobile kerogen-based product is treated with an acid to reduce the pH of the mobile kerogen-based product to a target value. Dissolved reaction products that are relatively insoluble in aqueous fluid at that pH form a separate phase, at least a portion of which is isolated from the remaining mobile kerogen-based product. Two phase separation methods are known. In one embodiment, the separation is facilitated by adding an organic extraction fluid, before, during or after acidification, for extracting the relatively insoluble products from the aqueous mobile kerogen-based product. After recovery of the separate organic acid phase, the mobile kerogen-based product is further acidified to progressively lower pH values, and the separate organic acid liquid phase that is produced with each step of acidification is recovered, optionally with the use of additional amounts of one or more organic extraction fluids.

When carbonate or bicarbonate containing materials are present in the formation fluid, increasing the amount of added acid will also generally increase the amount of evolved carbon dioxide. In some situations, the generated carbon dioxide is captured and used, for example, for manufacturing and commercial applications, for enhancing the recovery of hydrocarbons from subsurface reservoirs, or disposed, for example in subsurface cavities, to reduce carbon dioxide emissions into the atmosphere.

In one embodiment, separation of the organic acids from an aqueous mobile kerogen-based product is facilitated by contacting the product with an organic extraction fluid, which is selected to be relatively insoluble in the aqueous fluid, to have a high solubility for organic acids, to have adequate chemical stability at the conditions of the extraction and to be relatively easily separated from the organic acids in a subsequent separation step. Contacting the product with the organic extraction fluid produces a two phase liquid system, in which at least a portion of the acids in the aqueous product is extracted into the organic extraction fluid to form an acid rich extraction fluid, which is then recovered. The organic extraction fluid may be selected to preferentially partition a certain group of organic acids, so as to separate the organic acid product into groups by one or more desired physical and/or chemical property. The organic acids are separated from the organic extraction fluid using known separation methods, including distillation.

Typical organic extraction fluids include C₄ to C₂₁ hydrocarbons, including naphtha, diesel fuel, and gas oils; alcohols, including methanol, ethanol, propanol, butanol; aromatics, including benzene, toluene, the xylenes and alkyl substituted variations thereof; ethers; ketones; esters; tetralin; n-methyl-2-pyrrolidone; tetrahydrofuran; 2-methyl tetrahydrofurane.

Extraction conditions are generally mild, including a temperature, for example in the range from 0° C. to 200° C.; or in the range from 10° C. to 150° C.; or in the range from 20° C. to 100° C.; or even in the range from 25° C. to 75° C.

In general, an organic extraction fluid is use in the process is recycled to the process. In one embodiment, the process comprises extracting at least a portion of the organic acids into a first organic extraction fluid to form an acid rich extraction fluid; isolating at least a portion of the organic acids from the acid rich extraction fluid, and forming a second organic extraction fluid; and recycling the second organic extraction fluid to the extraction step.

Organic acids may be isolated from the mobile kerogen-based product using esterification. In general, the esters that are formed are less soluble in an aqueous fluid than are the organic acids. Insoluble esters are separated from the aqueous fluid by liquid-liquid separation techniques.

Products

It may be desirable to recover the organic acids from the mobile kerogen-based product as a syncrude which contains at least a portion of the organic acids that are insoluble in aqueous fluid at a pH of less than 2.0 or at a pH of less than 1.5. The syncrude prepared in this way will include organic acids of C₁₂ and higher, with deceasing amounts of organic acids of carbon number below C₁₂, depending on the particular acids. In one embodiment, the syncrude will include organic acids in the range of C₁₂ to C₃₅; or C₁₂ to C₃₀; or C₁₂ to C₂₀. Syncrude is a suitable feedstock for refining, petrochemical and power generating facilities.

The kerogen fragments that are recovered from the mobile kerogen-based product are generally very high molecular weight molecular clusters with sufficient numbers of acid functions to be mobilized in aqueous or organic solution. These kerogen fragments have a lower molecular mass than the naturally occurring kerogen itself, and with the characteristic chemical and conformational complexity of the kerogen structures from which they are derived. In one embodiment, the kerogen fragments are C₃₅+ organic acids. In one embodiment, the kerogen fragments have a molecular weight of greater than 1000 daltons. In one embodiment, at least a portion of the kerogen fragments have a molecular mass of up to 12,000 to 15,000 Daltons. In one embodiment, at least a portion of the kerogen fragments have a molecular mass of greater than 15,000 daltons.

The C₁₀ to C₃₅ organic acids are important for preparing fuels and lubricants, petrochemicals and petrochemical feedstocks, refinery raw materials and process oils. Many specialized products have been proposed for organic acids in this molecular weight range. For example, refinery processes such as hydroprocessing, hydrogenation, saturation, hydrotreating, hydrocracking, isomerization, fluid catalytic cracking, thermal cracking, esterification, oligomerization, reforming, alkylation, denitrification and desulfurization are suitable for upgrading the organic acids to commercially valuable products.

In some situations, it may be desirable to leave a relatively small amount of acids in the treated fluid produced after the organic acids are removed from the mobile kerogen-based product after acidification and organic acid recovery. For example, the treated formation fluid from the isolation step contains low amounts of organic acids and other organic molecules, which may provide surfactant properties to the treated formation fluid. The treated fluid containing low amounts of organic acids and other organic molecules is referenced herein as an organic acid lean fluid and is typically aqueous. In one embodiment, the organic acid lean fluid comprises C₂ to C₁₀ organic acids. In an embodiment, the organic acid lean fluid comprises organic acids in the range of from 0.001 wt % to 10 wt %.

The treated aqueous may be recycled, for example, for additional reaction and/or extraction and recovery of mobile kerogen-based products from the subsurface shale formation. As such, the process is integrated and uses a product stream in creating additional mobile kerogen-based products. This integration creates additional efficiencies in the process, creating more desired products and using a broader range of the products created.

As such, in one embodiment an integrated process for extracting kerogen-based products from a subsurface shale formation comprising kerogen in an inorganic matrix is provided. This integrated process comprises providing an oxidant to the kerogen in the subsurface shale formation; contacting the kerogen in the subsurface shale formation with the oxidant at a temperature in the range from 0° C. and 200° C. to form organic acids; mobilizing at least a portion of the organic acids as organic acid reaction products from the subsurface shale to produce a mobile kerogen-based product; treating the mobile kerogen-based product to provide a product stream comprising C₁₂ and higher organic acids and an organic acid lean fluid comprising C₂ to C₁₀ organic acids; and recycling the organic acid lean fluid to the subsurface shale formation.

Depending on the processing used to isolate organic acids from the mobile kerogen-based product, the organic acid lean fluid may range in pH from 2 or less to above 8.5. This organic acid lean fluid may be modified and prepared for recycling with an added oxidant as a reactive fluid to the kerogen in the subsurface shale. When used as a recycle reactive fluid, oxidant is added to the organic acid lean fluid and then recycled to the subsurface shale formation. The oxidant can be added in an amount of from 0.1 wt % to 40 wt %. The pH of the organic acid lean fluid can be tailored to the effective range for the particular oxidant or oxidant mixture. Additional surfactant may also be added as required. If necessary to achieve the target pH, an alkaline material can be added to the organic acid lean fluid prior to recycling.

The organic acid lean fluid may also be prepared for recycling as an extractive fluid. As such, the organic acid aqueous fluid can be isolated and recycled to the subsurface shale formation for mobilizing at least a portion of the organic acids as organic acid reaction products to produce a mobile kerogen-based product. When used as recycle extractive fluid, the pH of the organic acid lean fluid can be tailored to the effective range for mobilizing at least a portion of the organic acids as organic acid reaction products. If necessary to achieve the target pH, an alkaline material can be added to the organic acid lean fluid prior to recycling. Additional surfactant may also be added as required.

One embodiment of the process includes providing an oxidant to the kerogen in the subsurface shale formation; contacting the kerogen in the subsurface shale formation with the oxidant at a temperature in the range of between 0° C. and 200° C. to form organic acids; mobilizing at least a portion of the organic acids as organic acid reaction products from the subsurface shale formation to produce a mobile kerogen-based product; treating the mobile kerogen-based product to provide a product stream comprising C₁₂ and higher organic acids and an organic acid lean fluid comprising C₂ to C₁₀ organic acids; combining the organic acid aqueous fluid with an oxidant to provide a recycling fluid; and recycling the recycle fluid to the subsurface shale formation and contacting the kerogen in the subsurface shale formation with the oxidant in the recycle fluid for additional oxidation and formation of organic acids.

Another embodiment of the process includes providing an oxidant to the kerogen in the subsurface shale formation; contacting the kerogen in the subsurface shale formation with the oxidant at a temperature in the range of between 0° C. and 200° C. to form organic acids; mobilizing at least a portion of the organic acids as organic acid reaction products from the subsurface shale formation to produce a mobile kerogen-based product; treating the mobile kerogen-based product to provide a product stream comprising C12 and higher organic acids and an organic acid lean fluid comprising C₂ to C₁₀ organic acids; isolating the organic acid aqueous fluid as a recycling fluid; and recycling the recycle fluid to the subsurface shale formation and mobilizing at least a portion of the organic acids as organic acid reaction products to produce a mobile kerogen-based product.

The organic acid lean fluid can also be separated into two portions with one portion being used as additional reactive fluid with added oxidant and one portion being used as extractive fluid to assist in mobilizing at least a portion of the organic acids as organic acid reaction products to produce a mobile kerogen-based product.

Upgrading

As described, organic acids and other kerogen reaction products are separated from the mobile kerogen-based product. In further embodiments, the extracted kerogen-based product is upgraded to yield one or more commercial petroleum-based products. Various techniques common in the industry (e.g., hydroprocessing, hydrogenation, saturation, hydrotreating, hydrocracking, isomerization, fluid catalytic cracking, thermal cracking, esterification, oligomerization, reforming, alkylation, denitrification and desulfurization) may be employed to obtain a desired commercial product from the extracted kerogen-based product. Such upgrading is largely dependent on the nature of the extracted kerogen-based product relative to the commercial product that is desired.

The organic acids are used, for example, in the production of fuels, lubricant and lubricant base oils, polymers, pharmaceuticals, solvents, petrochemicals and food additives. In one embodiment, the acids are separated by e.g., chemical type or boiling range for specific chemical and petrochemical applications, including feedstock and end use applications. In one embodiment, at least some of the acids are used as feedstocks to make lubricating oil base stocks having a viscosity greater than or equal to 3 cSt at 40° C.; a pour point at or below 20° C., or at or below 0° C.; and a VI at least 70, or at least 90, or at least 120. It is optionally used with additives, and/or other base oils, to make a finished lubricant. The finished lubricants can be used in passenger car motor oils, industrial oils, and other applications. When used for passenger car motor oils, base oils meet the definitions of the current version of API Base Oil Interchange Guidelines 1509.

In general, C₂₀− organic acids find particular use in the production of fuels, lubricant and lubricant base oils, polymers, pharmaceuticals, solvents, petrochemicals and food additives. Therefore, in one embodiment, a method for increasing the value of a kerogen-based product includes isolating C₂₀+ organic acids and C₂₀− organic acids from the mobile kerogen-based product, and converting at least a portion of the C₂₀+ organic acids to C₂₀− organic acids. The separation step may include a process selected from the group consisting of pH titration, fractional neutralization, esterification, extraction, distillation, membrane separation, froth flotation, phase separation, electrostatic separation, filtering, centrifugal separation, coalescence, precipitation, thermal separation, steam distillation, and any combination thereof, in any order. In one embodiment, the mobile kerogen-based product from which the C₂₀+ and C₂₀− organic acids are isolated is treated at a pH in the range from 1.5 to 7 to achieve the separation. In one embodiment, the C₂₀+ organic acids are cracked in a process that converts at least a portion of the C₂₀+ organic acids to C₂₀− hydrocarbon products. In one embodiment, unconverted C₂₀+ organic acids are recycled to the cracking process, until virtually all of the C₂₀+ organic acids are reduced to C₂₀− forms. Exemplary cracking reactions include pyrolysis, partial oxidation, and fluid catalytic cracking and hydrocracking In one embodiment, partial oxidation is conducted in the presence of an oxidant. In one embodiment, the C₂₀− hydrocarbon product is upgraded, using a process selected from the group consisting of hydroprocessing, hydrogenation, saturation, hydrotreating, hydrocracking, isomerization, fluid catalytic cracking, thermal cracking, esterification, oligomerization, reforming, alkylation, denitrification, desulfurization, and combinations thereof. In another embodiment, a blend of the C₂₀− hydrocarbon product and the C₂₀− organic acids are blended, and the blend is upgrading, using a process selected from the group consisting of hydroprocessing, hydrogenation, saturation, hydrotreating, hydrocracking, isomerization, fluid catalytic cracking, thermal cracking, esterification, oligomerization, reforming, alkylation, denitrification, desulfurization, and combinations thereof. In one embodiment, the upgraded products are useful as a refinery feedstock, a fuel or lubricant blendstock, a reaction intermediate, a chemical feedstock, or a chemical intermediate blendstock.

In one embodiment, at least a portion of the organic acids in the mobile kerogen-based product are solid organic acids. Some of the solid, high molecular weight organic acids are difficult to dissolve in a solvent or to melt without decomposing. Accordingly, in one embodiment, the C₃₅+ organic acids that are isolated from the mobile kerogen-based product is cracked prior to downstream upgrading processes. In one such embodiment, the cracking process is selected from the group consisting of pyrolysis, partial oxidation, fluid catalytic cracking and hydrocracking The C₃₅− hydrocarbon products from the cracking reaction are further upgraded in a process selected from the group consisting of hydroprocessing, hydrogenation, saturation, hydrotreating, hydrocracking, isomerization, fluid catalytic cracking, thermal cracking, esterification, oligomerization, reforming, alkylation, denitrification, desulfurization, and combinations thereof. In one embodiment, the at least a portion of the C₃₅− hydrocarbon products are blended with at least a portion of the C₃₅− organic acids, and the blend upgraded in a process selected from the group consisting of hydroprocessing, hydrogenation, saturation, hydrotreating, hydrocracking, isomerization, fluid catalytic cracking, thermal cracking, esterification, oligomerization, reforming, alkylation, denitrification, desulfurization, and combinations thereof. In one embodiment, the upgraded products are useful as a refinery feedstock, a fuel or lubricant blendstock, a reaction intermediate, a chemical feedstock, or a chemical intermediate blendstock.

In one such embodiment, the process includes pyrolyzing the solid organic acids to form C₂₀− hydrocarbon products and C₂₀+ products; recovering the C₂₀+ products; and pyrolyzing the C₂₀+ products. In another such embodiment, the process includes pyrolyzing the solid organic acids to form C₃₅− hydrocarbon products and C₃₅+ products; recovering the C₃₅+ products; and pyrolyzing the C₃₅+ products.

In one embodiment, at least some of the acids are used as feedstocks to make distillate fuels, generally boiling in the range of about C5-700° F. (121°-371° C.) as determine by the appropriate ASTM test procedure. The term “distillate fuel” is intended to include gasoline, diesel, jet fuel and kerosene boiling range fractions. The kerosene or jet fuel boiling point range is intended to refer to a temperature range of about 280°-525° F. (138°-274° C.) and the term “diesel boiling range” is intended to refer to hydrocarbon boiling points of about 250°-700° F. (121°-371° C.). Gasoline or naphtha is normally the C₅ to 400° F. (204° C.) endpoint fraction of available hydrocarbons. The boiling point ranges of the various product fractions recovered in any particular refinery or synthesis process will vary with such factors as the characteristics of the source, local markets, product prices, etc. Reference is made to ASTM standards D-975, D-3699-83 and D-3735 for further details on kerosene, diesel and naphtha fuel properties.

In one embodiment, the organic acids are upgraded in a hydrotreating reaction zone to remove heteroatoms such as oxygen, nitrogen and sulfur and to saturate olefins and aromatics. Hydrotreating conditions include a reaction temperature between 400° F.-900° F. (204° C.-482° C.), or between 650° F.-850° F. (343° C.-454° C.); a pressure between 500 to 5000 psig (pounds per square inch gauge) (3.5-34.6 MPa), or between 1000 to 3000 psig (7.0-20.8 MPa); a feed rate (LHSV) of 0.5 hr-1 to 20 hr-1 (v/v); and overall hydrogen consumption 300 to 2000 scf per barrel of liquid hydrocarbon feed (53.4-356 m3 H2/m3 feed). The hydrotreating catalyst will generally be a composite of a Group VI metal or compound thereof, and a Group VIII metal or compound thereof supported on a porous refractory base such as alumina. Examples of hydrotreating catalysts are alumina supported cobalt-molybdenum, nickel sulfide, nickel-tungsten, cobalt-tungsten and nickel-molybdenum. Other examples of hydrotreating catalysts contain a platinum group metal such as platinum and/or palladium. Typically such hydrotreating catalysts are presulfided.

In one embodiment, the organic acids or reaction products derived from the organic acids are hydrocracked. The hydrocracking reaction zone is maintained at conditions sufficient to effect a boiling range conversion of the organic acids or derivatives thereof to the hydrocracking reaction zone, so that the liquid hydrocrackate recovered from the hydrocracking reaction zone has a normal boiling point range below the boiling point range of the feed. The hydrocracking step reduces the size of the hydrocarbon molecules, hydrogenates olefin bonds, hydrogenates aromatics, and removes traces of heteroatoms resulting in an improvement in fuel or base oil product quality.

Typical hydrocracking conditions include a reaction temperature between 400° F. and 950° F. (204° C.-510° C.) or between 650° F. and 850° F. (343° C.-454° C.); a reaction pressure between 500 and 5000 psig (3.5-34.5 MPa) or between 1500 and 3500 psig (10.4-24.2 MPa); a feed rate (in terms of volumes of feed at ambient conditions per volume of catalyst per hour) between 0.1 and 15 hr-1 (v/v) or between 0.25 and 2.5 hr-1; and hydrogen consumption 500 to 2500 scf per barrel of liquid hydrocarbon feed (89.1-445 m3 H2/m3 feed). Generally, more severe conditions within these ranges will be used with higher boiling feedstocks and depending on whether gasoline, middle distillate or lubricating oil is desired as the primary economic product. The hydrocrackate is then separated into various boiling range fractions. The separation is typically conducted by fractional distillation preceded by one or more vapor-liquid separators to remove hydrogen and/or other tail gases.

The hydrocracking catalyst generally comprises a cracking component, a hydrogenation component and a binder. Such catalysts are well known in the art. The cracking component may include an amorphous silica/alumina phase and/or a zeolite, such as a Y-type or USY zeolite. The binder is generally silica or alumina. The hydrogenation component will be a Group VI, Group VII, or Group VIII metal or oxides or sulfides thereof, preferably one or more of molybdenum, tungsten, cobalt, or nickel, or the sulfides or oxides thereof. If present in the catalyst, these hydrogenation components generally make up from about 5% to about 40 wt. % of the catalyst. Alternatively, platinum group metals, especially platinum and/or palladium, may be present as the hydrogenation component, either alone or in combination with the base metal hydrogenation components molybdenum, tungsten, cobalt, or nickel. If present, the platinum group metals will generally make up from about 0.1% to about 2 wt. % of the catalyst.

In one embodiment, the organic acids or reaction products derived from the organic acids are hydroisomerized. Typical hydroisomerization conditions are well known in the literature and can vary widely. Isomerization processes are typically carried out at a temperature between 200° F. and 700° F. or between 300° F. to 650° F., with a feed rate between 0.1 and 10 hr-1 or between 0.25 and 5 hr-1. Hydrogen is employed such that the mole ratio of hydrogen to hydrocarbon is between 1:1 and 15:1. Catalysts useful for isomerization processes are generally bifunctional catalysts that include a dehydrogenation/hydrogenation component and an acidic component. The acidic component may include one or more of amorphous oxides such as alumina, silica or silica-alumina; a zeolitic material such as zeolite Y, ultrastable Y, SSZ-32, Beta zeolite, mordenite, ZSM-5 and the like, or a non-zeolitic molecular sieve such as SAPO-11, SAPO-31 and SAPO-41. The acidic component may further include a halogen component, such as fluorine. The hydrogenation component may be selected from the Group VIII noble metals such as platinum and/or palladium, from the Group VIII non-noble metals such as nickel and tungsten, and from the Group VI metals such as cobalt and molybdenum. If present, the platinum group metals will generally make up from about 0.1% to about 2 wt. % of the catalyst. If present in the catalyst, the non-noble metal hydrogenation components generally make up from about 5% to about 40 wt. % of the catalyst.

In one embodiment, the organic acids or reaction products derived from the organic acids are cracked in a fluid catalytic cracking unit (FCC). In such fluidized catalytic cracking, high molecular weight hydrocarbon liquids and vapors are contacted with hot, finely divided solid catalyst particles in an elongated riser or transfer line reactor. The transfer line is usually in the form of a riser tube and the contacting time is on the order of a few seconds, say from 0.5 to 8 seconds, and generally not over about 4 seconds. During this short period, catalysts at temperatures in the range about 1100° F. to 1400° F. are contacted with a hydrocarbon feedstock which is heated to a temperature of about 300° F. to 800° F. The reaction is one of essentially instantaneous generation of large volumes of gaseous hydrocarbons. The hydrocarbons and catalyst mixture flows out of the riser tube into a reactor vessel wherein the resultant gaseous hydrocarbons are taken off for distillation into various product fractions defined by boiling ranges. The spent catalyst is then separated in the reactor vessel and stripped of hydrocarbons by passing the catalyst through a stripper section which includes steam flowing up through the down-flowing catalyst usually for a period of 1 to 3 minutes. Catalyst is then returned to a regenerator where residual hydrocarbons, called “coke”, on the spent catalyst are burned off by passing a stream of an oxygen-containing gas, such as air, or oxygen-enriched air, through the catalyst until substantially all the carbon is burned from the particles. The heat generated in this regeneration step is used as a heat source to heat the catalyst and thus provide elevated temperatures needed for reaction with the incoming hydrocarbon feed. Regenerated hot catalyst is then recycled to the riser cracking zone wherein the feed is cracked to form more gaseous products. In one embodiment, the fluid catalytic cracking reaction of the organic acids is conducted at a temperature of between 1200° F. and 1400° F. (600° C. to 800° C.). In another embodiment the fluid catalytic cracking reaction of the organic acids is conducted at a temperature of between 250° C. and 490° C.

A typical catalyst comprises 10%-60% w/w of a solid acid, 0%-50% w/w of alumina, 0%-40% w/w of silica, the remainder being kaolin. The solid acid may be a zeolite of the ZSM type, a zeolite of the faujasite type, a zeolite of the mordenite type, silico-aluminum phosphate (SAPO) or aluminum phosphate (ALPO).

Many refineries operate a single reactor for fluid catalytic cracking of gas oil or residue. In some situations, refineries may employ an FCCU possessing two reactors working in simultaneous operation. In such units the streams of spent catalyst from two reactors are mixed in the same rectification section having a single regenerator to burn off coke deposited on the catalyst. In addition such reactors may function in an independent manner with respectively different types of charge and differing reaction temperatures. The reaction severity applied to each reactor may be totally different, making it possible to adjust them to preestablished operational objectives. In this manner it is possible to carry out the processing of the organic acids under milder conditions, at temperatures between 250° C. and 490° C., for the production of diesel oil having a cetane number exceeding 40, while simultaneously carrying out the processing of conventional heavy gas oils or residues under more severe conditions, employing a single catalyst flow for both processes.

The method of the present invention for converting the organic acids to esters involves blending suitable amounts of an alcohol, such as alcohol, and an acid catalyst with the organic acids. The reaction mixture is then subjected to conditions suitable for forming the esters.

A suitable amount of alcohol for the method of the present invention is an amount that is about 100% to about 470% of the theoretical amount needed to convert all organic acids into esters. The theoretical amount of alcohol needed to convert all organic acids into esters is defined as an equal number of alcohol molecules as that of organic acid molecules. In one embodiment, an amount of alcohol about 120% to about 300% of the theoretical amount is used in the method of the present invention. In another embodiment, an amount of alcohol between 100% and 150% of the theoretical amount is used. In still another embodiment, an amount of alcohol about 270% of the theoretical amount is used.

Suitable acid catalysts for converting organic acids to esters are known in the art. Any of these catalysts can be used in the process. Examples of these catalysts include but are not limited to sulfuric acid, hydrogen chloride and p-toluenesulfonic acid. When sulfuric acid is used, a suitable amount is about 0.1% to about 7.5% by weight in the reaction mixture. In one embodiment, the amount of sulfuric acid used is about 0.6% to about 5.8% or about 1.2%. When other acid catalysts are used, a skilled artisan either knows or can easily determine the suitable amount that can be added into the reaction mixture.

The speed that organic acids are converted to esters in the reaction mixtures described above is a function of the reaction temperature—the higher the reaction temperature, the higher the speed. In one embodiment, the reaction temperature used for esterifying the acids is at least 20° C.; or 25° C.; or 30° C.; or 35° C.; or 40° C.; or 45° C. with stirring. Most preferably, the reaction temperature is kept at about at least 50° C.; or 55° C.; or 60° C.; or 65° C. In one embodiment, the reaction temperature is the boiling point of the alcohol at the reaction pressure. The reaction pressure for esterification is generally equal to or slightly above (e.g., 200 psig) atmospheric pressure.

The reaction time needed to convert a desired percentage of organic acids into esters under specific amounts of alcohol, acid catalyst and reaction temperature can readily be determined by a skilled artisan. For example, a small sample of the reaction mixture can be taken at different time points and the organic acid level and ester level can be determined. Generally speaking, the reaction time range goes from 0.5 hr to 2.0 hr; or to 3.0 hr; or to 5.0 hr; or to 10 hr.

Example

This example illustrates the effectiveness of potassium permanganate for producing high molecular weight organic acids in reactions with kerogen.

Kerogen was separated from a sample of oil shale that contained kerogen. The separated kerogen was largely organic matter, with a small amount of inorganic matter remaining from the inorganic substrate in which the kerogen originated. For this example, 2.50 grams of kerogen (organic matter basis) was combined with a solution containing 0.5 g KMnO₄ in 100 ml of 1% KOH solution. The kerogen/KMnO4 mixture was stirred at 75° C. until the solution had lost its color, with no visual evidence of the purple permanganate color remaining In general, this reaction took several hours, and up to 12 hours in some cases. The kerogen was then allowed to settle, and was separated from the solution. The kerogen was then rinsed with two 75 ml aliquots of 1% KOH solution. The two rinse solutions were set aside. The rinsed kerogen was then contacted with another aliquot of KMnO₄ solution, and the oxidation and washing steps were repeated. After five successive KMnO₄ treatments, the kerogen was washed with oxalic acid solution at low pH to dissolve MnO₂ which was deposited on the kerogen surface. The kerogen was then rinsed before the next KMnO₄ treatment step. At the end of 17 KMnO₄ treatments, the kerogen was effectively consumed, and the permanganate color of the solution no longer disappeared. All of the 1% KOH rinse solutions collected from each treatment step were combined and acidified to pH 2. High molecular weight acids in the acidified solution precipitated from solution and were recovered. Low molecular weight acids in the solution were extracted with methyl t-butyl ether and recovered by removing the ether solvent.

FIG. 4 illustrates the gas chromatographic separation of the low molecular weight acids. A high proportion of the low molecular weight (i.e., C₃₅−) organic acids are in the C₈ to C₁₂ range. In particular, FIG. 4 shows carbon chain-size distribution of low molecular weight organic acids (di-carboxylic acids and mono-carboxylic acids) in kerogen permanganate oxidation products determined by gas chromatography—mass spectrometry (GCMS) of their silyl derivatives. The high-pH aqueous reaction product solution was adjusted to ˜pH 2 and extracted with methyl t-butyl ether solvent to yield low molecular weight organic acids upon solvent removal. GCMS analysis showed these organic acids contain primarily straight (un-branched) alkyl chains. Hydroprocessing of this low molecular weight organic acids product to remove oxygen and other heteroatoms would provide the alkane mixture shown in the figure, where the number of carbon atoms in each of the major, straight-chain product peaks is labeled. The carbon number distribution of products range from ˜C₆ to ˜C₁₇ (with a maximum at C₉), covering the highly desirable gasoline, jet, and diesel transportation fuel hydrocarbon molecular weight range.

The high molecular weight (i.e., C₃₅+) organic acids were passed through a pyrolysis gas chromatograph, which thermally pyrolyzed the acids. FIG. 5 is a gas chromatographic trace of the pyrolyzed acids. In particular, FIG. 5 shows carbon chain-size distribution of hydrocarbon products formed by pyrolysis of high molecular weight organic acids in kerogen permanganate oxidation products determined by pyrolysis gas chromatography—mass spectrometry (pyrolysis-GCMS). The high-pH aqueous reaction product solution was adjusted to ˜pH 2 resulting in the precipitation of high molecular weight organic acids which were collected, washed with deionized water, and dried under vacuum. Pyrolysis-GCMS analysis showed these high molecular weight organic acids to yield primarily straight (un-branched) alkanes and alkenes upon heating to 500° C. in inert atmosphere. The number of carbon atoms in each of the major, straight-chain product peaks is labeled in the figure—each carbon number labels two peaks, consisting of an alkane and alkene pair, typical of pyrolysis/retort products. Hydroprocessing of the pyrolysis (retort) products shown in the figure, to remove alkenes and heteroatoms, would provide an alkane mixture with a carbon number distribution ranging from ˜C₅ to ˜C₃₁ (with a maximum at C₉), covering the highly desirable gasoline, jet, and diesel fuel hydrocarbon molecular weight range, with a small proportion of product in the fuel oil and lube oil hydrocarbon molecular weight range.

It is interesting to note that the profile of the pyrolyzed acids is very similar to the profile of the low molecular weight acids. In particular, a high proportion of the pyrolyzed organic acids are also in the C₈ to C₁₂ range.

A variation (i.e., alternate embodiment) on the above-described process is the application of some or part of such above-described methods to alternative sources, i.e., low-permeability hydrocarbon-bearing (e.g., oil and gas) formations, in situ coal, in situ heavy oil, in situ oil sands, and the like. General applicability of at least some of the above-described invention embodiments to any hydrocarbon-bearing formation exists. Surface processing applications may include upgrading of oil shale, coal, heavy oil, oil sands, and other conventional oils with asphaltenes, sulfur, nitrogen, etc.

Various modifications and alterations of this invention will become apparent to those skilled in the art without departing from the scope and spirit of the invention. Other objects and advantages will become apparent to those skilled in the art from a review of the preceding description. 

1. A process for extracting a kerogen-based product from a subsurface shale formation comprising subsurface shale, the process comprising the steps of: a. providing an oxidant to kerogen in subsurface shale; b. contacting the kerogen in the subsurface shale with the oxidant at a temperature in the range from 0° C. and 200° C. to form organic acids; and c. mobilizing at least a portion of the organic acids from the subsurface shale formation to produce a mobile kerogen-based product.
 2. The process according to claim 1, further comprising providing the oxidant to the kerogen combined with a carrier fluid selected from the group consisting of an aqueous fluid, an ethanol fluid or combinations thereof.
 3. The process according to claim 2, wherein the carrier fluid contains in the range from 0.1 wt. % to 40 wt. % of the oxidant.
 4. The process according to claim 2, wherein the carrier fluid has a pH in the range from 7 to
 14. 5. The process according to claim 2, wherein the carrier fluid has a pH in the range from 1.5 to 6.5
 6. The process according to claim 1, wherein the oxidant is selected from the group consisting of: oxone, oxone combined with one or more manganese porphyrin catalysts, peracetic acid, hydrogen peroxide, Fenton's reagent, benzoyl peroxide, a permanganate oxidant, and mixtures thereof.
 7. The process according to claim 1, further comprising providing the oxidant to the kerogen at a pH in a range from 7 to
 14. 8. The process according to claim 7, further comprising maintaining the pH in the range from 7 to 14 by supplying an alkaline material selected from the group consisting of a carbonate, a bicarbonate, an oxide and a hydroxide to the subsurface shale.
 9. The process according to claim 7, further comprising providing the oxidant to the kerogen at a pH in a range from 7 to
 9. 10. The process according to claim 1, further comprising contacting the kerogen with the first oxidant for a period of at least 4 hours.
 11. The process according to claim 1, further comprising providing a surfactant to the kerogen in the subsurface shale.
 12. The process according to claim 11, wherein the surfactant is an organic acid surfactant.
 13. The process according to claim 1, further comprising providing a reactive fluid to the kerogen, the reactive fluid comprising from 0.1 wt. % to 40 wt. % of the oxidant in a carrier fluid selected from the group consisting of an aqueous fluid, an ethanol fluid or mixtures thereof.
 14. The process according to claim 13, wherein the reactive fluid further comprises a sufficient amount of an alkaline material to yield a reactive fluid having a pH in a range from 7 to
 9. 15. The process according to claim 13, wherein the reactive fluid further comprises in the range from 2 wt. % to 10 wt. % of a surfactant.
 16. The process according to claim 1, further comprising contacting the kerogen with the oxidant at a pH in the range from 7 to 14 to form the organic acids.
 17. The process according to claim 16, further comprising maintaining the pH in the range from 7 to 14 by supplying an alkaline material selected from the group consisting of a carbonate, a bicarbonate, an oxide and a hydroxide.
 18. The process according to claim 16, further comprising contacting the kerogen with the oxidant at a pH in the range from 7 to
 9. 19. The process according to claim 1, further comprising providing a reactive fluid to the kerogen, the reactive fluid comprising from 0.1 wt. % to 40 wt. % of the oxidant in a carrier fluid selected from the group consisting of an aqueous fluid, an ethanol fluid or combinations thereof, the reactive fluid having a pH in the range from 7 to
 9. 20. The process according to claim 1, further comprising providing an oxidant to a formation fluid in contact with the kerogen, such that the formation fluid comprises from 0.1 wt. % to 40 wt. % of the oxidant and has a pH in the range of 7 to
 14. 21. The process according to claim 16, wherein the oxidant is oxone.
 22. The process according to claim 16, wherein the oxidant is hydrogen peroxide.
 23. The process according to claim 16, wherein the oxidant is a permanganate oxidant.
 24. The process according to claim 23, wherein the permanganate oxidant is selected from the group consisting of ammonium permanganate, NH₄MnO₄; calcium permanganate, Ca(MnO₄)₂; potassium permanganate, KMnO₄; and sodium permanganate, NaMnO₄.
 25. The process according to claim 1, further comprising providing the oxidant to the kerogen at a pH in the range from 1.5 to 6.5.
 26. The process according to claim 25, further comprising providing an acid material to the kerogen in the subsurface shale.
 27. The process according to claim 26, wherein the acid material is selected from the group consisting of inorganic acids, organic acids, carbon dioxide and carbon dioxide at supercritical conditions.
 28. The process according to claim 1, further comprising contacting the kerogen with the oxidant at a pH in the range from 1.5 to 6.5.
 29. The process according to claim 1, further comprising providing an oxidant to a formation fluid in contact with the kerogen, such that the formation fluid comprises from 0.1 wt. % to 40 wt. % of the oxidant and has a pH in the range of 1.5 to 6.5.
 30. The process according to claim 25, wherein the oxidant is peracetic acid.
 31. The process according to claim 25, wherein the oxidant is hydrogen peroxide.
 32. The process according to claim 25, wherein the oxidant is Fenton's reagent.
 33. The process according to claim 25, further comprising maintaining the pH in the range from 1.5 to 6.5 by supplying an alkaline material selected from the group consisting of a carbonate, a bicarbonate, an oxide and a hydroxide to the subsurface shale.
 34. The process according to claim 25, further comprising maintaining the pH in the range from 1.5 to 6.5 by supplying an acidic material selected from the group consisting of a mineral acid, an organic acid, and combinations thereof to the subsurface shale.
 35. The process according to claim 25, further comprising maintaining the pH in the range from 1.5 to 6.5 by supplying CO₂ to the subsurface shale.
 36. The process according to claim 1, further comprising mobilizing at least a portion of the organic acids at a pH in the range from 7 to
 14. 37. The process according to claim 36, further comprising mobilizing at least a portion of the organic acids at a pH in the range from 12 to
 14. 38. The process according to claim 36, further comprising mobilizing at least a portion of the organic acids at a pH in the range from 12 to 14, in the presence of alkaline material selected from the group consisting of a carbonate, a bicarbonate, an oxide and a hydroxide.
 39. The process according to claim 1, wherein the mobile kerogen-based product contains less than 0.5 wt. % of the oxidant.
 40. The process according to claim 1, wherein the mobile kerogen-based product contains less than 0.1 wt. % of the oxidant.
 41. The process according to claim 1, wherein the mobile kerogen-based product contains C₃₅− organic acids and C₃₅+ organic acids.
 42. The process according to claim 41, wherein the mobile kerogen-based product contains in the range from 5 wt. % to 50 wt. % organic acids.
 43. The process according to claim 41, wherein at least 50 wt. % of the organic acids in the mobile kerogen-based product are in the C₃₅+ range.
 44. The process according to claim 41, wherein at least 20 wt. % of the C₃₅+ organic acids in the mobile kerogen-based product have a molecular mass number of greater than 1000 daltons.
 45. The process according to claim 41, wherein at least 20 wt. % of the C₃₅− organic acids in the mobile kerogen-based product are in the C₈ to C₁₂ range.
 46. The process according to claim 41, wherein at least 30 wt. % of the organic acids in the mobile kerogen-based product are diacids.
 47. A process for extracting a kerogen-based product from a subsurface shale formation comprising subsurface shale, the process comprising the steps of: a. providing a reactive fluid, to kerogen in subsurface shale, the reactive fluid containing in the range from 0.1 wt. % to 40 wt. % of an oxidant, and having a pH in the range from 7 to 9; b. contacting the kerogen in the subsurface shale with the oxidant at a temperature in the range from 0° C. to 200° C. to form organic acids; and c. mobilizing at least a portion of the organic acids in a formation fluid having a pH in the range from 12 to 14 to produce a mobile kerogen-based product.
 48. A process for extracting a kerogen-based product from a subsurface shale formation comprising subsurface shale, the process comprising the steps of: a. providing an oxidant to a fluid in a subsurface shale formation that contains kerogen, to produce a formation fluid; b. contacting the kerogen in the subsurface shale with the formation fluid at a temperature in the range of between 0° C. and 200° C. to form organic acids; c. providing an alkaline material to the formation fluid to form a mobile kerogen-based product comprising the organic acids; and d. recovering at least a portion of the mobile kerogen-based product from the subsurface shale formation. 